Section 8
Chemical Stimulation
Table of Contents
Introduction ............................................................................................................................................... 8-5
Topic Areas............................................................................................................................................ 8-5
Learning Objectives ............................................................................................................................... 8-5
Unit A: Types of Acids.............................................................................................................................. 8-6
Hydrochloric Acid.................................................................................................................................. 8-6
Hydrofluoric-Hydrochloric Acid ........................................................................................................... 8-6
Additional Acids .................................................................................................................................... 8-6
Unit A Quiz............................................................................................................................................ 8-7
Unit B: Safety ............................................................................................................................................ 8-8
Safety Precautions.................................................................................................................................. 8-8
Unit B Quiz ............................................................................................................................................ 8-9
Unit C: Reactions of Hydrochloric Acid ................................................................................................. 8-10
HCL Reactions..................................................................................................................................... 8-10
Unit C Quiz .......................................................................................................................................... 8-12
Unit D: Corrosion Inhibitors.................................................................................................................... 8-13
Corrosion of Metals ............................................................................................................................. 8-13
MSA Inhibitors .................................................................................................................................... 8-14
Unit D Quiz.......................................................................................................................................... 8-15
Unit E: Carbonate Acidizing ................................................................................................................... 8-16
Matrix Acidizing.................................................................................................................................. 8-16
Expected Results .................................................................................................................................. 8-17
Types of Porosity ................................................................................................................................. 8-17
Fracture Acidizing................................................................................................................................ 8-17
Formation Core and Fluid Testing ....................................................................................................... 8-17
Tubing Movement Program ................................................................................................................. 8-19
Fracture Acidizing Plan Calculations .................................................................................................. 8-19
Acid Systems ....................................................................................................................................... 8-19
Additional Reference ........................................................................................................................... 8-21
Preflushes............................................................................................................................................. 8-21
Acid Placement Techniques................................................................................................................. 8-22
Unit E Quiz .......................................................................................................................................... 8-24
Unit F: Sandstone Acidizing.................................................................................................................... 8-25
Hydrochloric Acid................................................................................................................................ 8-25
Hydrofluoric Acid................................................................................................................................ 8-25
Damage Removal................................................................................................................................. 8-25
Reaction Rates ..................................................................................................................................... 8-25
Sandstone-2000 TM ............................................................................................................................... 8-26
© 2005, Halliburton
8•1
Stimulation I
Chemical Stimulation
Formation Conditioning....................................................................................................................... 8-26
Clays .................................................................................................................................................... 8-26
Secondary Precipitation ....................................................................................................................... 8-28
Acid Systems ....................................................................................................................................... 8-29
Unit F Quiz .......................................................................................................................................... 8-33
Unit G: Damage Removal – Mud............................................................................................................ 8-34
Mud Removal....................................................................................................................................... 8-34
Limestone Formations.......................................................................................................................... 8-34
Acid–Surfactant Mud Removal Solutions (MCA-III) ........................................................................ 8-34
Non-Acid Mud Removal Solutions (Mud-Flush) ................................................................................ 8-35
Sandstone Formations .......................................................................................................................... 8-35
Hydrofluoric-Hydrochloric Acid Mixtures (HF Acid)......................................................................... 8-35
Oil Base Muds...................................................................................................................................... 8-35
True Oil Base Muds ............................................................................................................................. 8-36
N-VER-Sperse ..................................................................................................................................... 8-36
Additional References.......................................................................................................................... 8-36
Unit G Quiz: Damage Removal-Mud .................................................................................................. 8-37
Unit H: Paraffins and Asphaltenes .......................................................................................................... 8-38
Paraffins ............................................................................................................................................... 8-38
Cloud Point and Pour Point.................................................................................................................. 8-38
Factors Affecting Paraffin Deposition ................................................................................................. 8-39
Loss of Volatile Constituents from the Crude...................................................................................... 8-39
Suspended Particles in the Crude......................................................................................................... 8-39
Conditions Favoring Paraffin Deposition ............................................................................................ 8-39
Paraffin Precipitation during Fracture Stimulation .............................................................................. 8-40
Methods Used to Remove Deposits ..................................................................................................... 8-40
Methods for Decreasing the Severity of Deposition ............................................................................ 8-42
Asphaltenes .......................................................................................................................................... 8-44
Targon® II Solvent ............................................................................................................................... 8-44
Unit H Quiz.......................................................................................................................................... 8-45
Unit I: Scale Removal and Prevention..................................................................................................... 8-46
Scale Effects......................................................................................................................................... 8-46
Types of Scale...................................................................................................................................... 8-46
Scale Formation ................................................................................................................................... 8-47
Scale Form ........................................................................................................................................... 8-47
Acid Soluble Scale Removal................................................................................................................ 8-48
Regular Inhibited Acid......................................................................................................................... 8-48
Penetrating Acid................................................................................................................................... 8-48
Non-Emulsifying Acid (NE) ................................................................................................................ 8-49
Fe Acid................................................................................................................................................. 8-49
Multiple Service Acid (MSA).............................................................................................................. 8-49
Paragon Acid Dispersion (PAD).......................................................................................................... 8-49
Acid Insoluble Scale Removal ............................................................................................................. 8-50
GYPSOL .............................................................................................................................................. 8-50
Liquid Scale Disintegrator ................................................................................................................... 8-50
Equations for Determining Volume of Scale Present .......................................................................... 8-52
gallons 15% HCL
× 27.5906 ft 3
Acid Volume = 180
3
........................................................................... 8-53
ft
= 4966.308 gallons
Scale Inhibition .................................................................................................................................... 8-53
© 2005, Halliburton
8•2
Stimulation I
Chemical Stimulation
Scalechek® Scale Prevention Service................................................................................................... 8-53
Scalecheck® HT ................................................................................................................................... 8-53
Calchek Service.................................................................................................................................... 8-54
Protex-All Inhibitor.............................................................................................................................. 8-54
Chemical Placement Technique (CPT)................................................................................................ 8-55
Unit I Quiz ........................................................................................................................................... 8-56
Unit I Quiz ........................................................................................................................................... 8-57
Unit J: Placement Aids ............................................................................................................................ 8-59
Temporary Bridging Agents ................................................................................................................ 8-59
Selection of Bridging Agent ................................................................................................................ 8-59
Well Completion Type......................................................................................................................... 8-60
Placement Techniques.......................................................................................................................... 8-60
Carrier Fluid......................................................................................................................................... 8-60
Concentration of Bridging Agent......................................................................................................... 8-60
Particle Size Distribution ..................................................................................................................... 8-61
MATRISEAL® O ................................................................................................................................. 8-61
Matriseal® OWG Diverter.................................................................................................................... 8-62
Temporary Bridging Agents in Conjunction with Temblok Diverting Materials................................ 8-62
Unit J Quiz ........................................................................................................................................... 8-63
Unit K: Job Calculations.......................................................................................................................... 8-64
Calculations for Spotting Acid to the End of Tubing or Packer .......................................................... 8-64
Calculations for Balanced Acid Spot ................................................................................................... 8-65
Calculations for Flush and OverFlush.................................................................................................. 8-66
Unit Quiz K:......................................................................................................................................... 8-67
Self-Check Test for Section 8: Chemical Stimulation............................................................................. 8-68
Answer Key ............................................................................................................................................. 8-70
Self Check Test .................................................................................................................................... 8-73
© 2005, Halliburton
8•3
Stimulation I
Chemical Stimulation
Use for Section notes…
© 2005, Halliburton
8•4
Stimulation I
Chemical Stimulation
Introduction
•
Chemical stimulation is an important method of
increasing oil and gas well production which,
even today, is still experiencing rapid technical
growth. Different processes have been used
extensively since 1935.
Job Calculations
Learning Objectives
Upon completion of this section, you will be
able to:
Topic Areas
•
identify the acid types
The section units are:
•
list critical safety precautions
•
Types of Acids
•
•
Safety
•
identify the primary corrosion factors and
list the inhibitors that help decrease
corrosion
Reactions of Hydrochloric Acids
•
•
Corrosion Inhibitors
identify damage removal methods of mud,
scale and paraffin
•
Limestone Acidizing
•
•
Sandstone Acidizing
identify acidizing treatments for limestone
and sandstone
•
Damage Removal – Mud
•
identify types of acids
•
Paraffin and Asphaltene Deposits
•
identify inhibitors
•
Scale Removal and Prevention
•
calculate placement of acid
•
Placement Aids
© 2005, Halliburton
8•5
Stimulation I
Chemical Stimulation
Unit A: Types of Acids
Major acids used in chemical stimulation
include hydrochloric acid, hydrofluorichydrochloric acid mixtures, and organic acids.
This unit will explain the roles of these acids in
chemical stimulation.
Hydrofluoric-Hydrochloric Acid
A Hydrofluoric-Hydrochloric (HF) acid mixture
is the basic acid for treating sandstone
formations with less than 20% HCL solubility.
These mixtures are used for removal of damage
caused by drilling mud, filtrate water, waterswollen clays, migrating clays, and other small
formation particles. HF acid is typically
prepared in the field by adding ammonium bifluoride (ABF) to HCL. Hydrofluoric acid is
discussed further in Unit F, Sandstone
Acidizing.
Hydrochloric Acid
Hydrochloric (HCL) acid containing inhibitors
is the base solution for most oil field acidizing
treatments. Depending on the use and
requirements of the treatments, the concentration
may range from 1% to about 35%. Hydrochloric
acid reacts rapidly with carbonate formations
and is used in treating sandstone formations.
HCL can serve as the basic acid for damage
removal in addition to matrix and fracture
acidizing.
Additional Acids
Two organic acids also used are formic and
acetic. These are weaker than hydrochloric acid
and exhibit less corrosion problems than HCL;
which means their hydrogen ions are released
more slowly than HCL with most materials
found in wells. Ten- percent formic acid will
dissolve as much limestone as eight- percent
HCL. Six percent HCL will dissolve as much
limestone as ten-percent acetic acid. Due to their
low degree of corrosiveness, organic acids can
be used at higher temperatures for acidizing
treatments. Acetic acid is the only acid that
won’t damage chrome plating. It is useful for
acidizing wells that contain pumps using chrome
plated parts. Organic acids may be used with
HCL to allow deeper penetration and to provide
unique etching properties with some formations.
Hydrochloric acid is a mixture of hydrogen and
chlorine gases dissolved in water. This gas is
called hydrogen chloride and is readily soluble
in water up to 42% by weight at 60°F.
However, a solution of this concentration is
impractical since hydrogen chloride gas will
come out of hydrochloric acid at temperatures
above 60°F.
Commercially available hydrochloric acid has
been standardized at 20° Be (Baume). This is
equivalent to 31.45% acid, by weight, with a
density of 9.67 lb/gal. Higher concentrations of
acid can be purchased at 22° Be, or 35.2% acid.
It has a specific gravity of 1.179 and a density of
9.82 lb/gallon.
© 2005, Halliburton
8•6
Stimulation I
Chemical Stimulation
Unit A Quiz
Fill in the blanks with one or more words to check your progress in Unit A.
1. Two major acids used in chemical stimulation are ____________________ and
____________________.
2. Hydrochloric acid can serve as the basic acid for ____________________ ____________________
in addition to ____________________ and ____________________ acidizing.
3. Commercially available hydrochloric acid is standardized at __________ °Be or __________%.
4. Hydrofluoric – Hydrochloric acid mixture is the basic acid for treating ____________________
formations having 20% or less HCL solubility.
5. Two organic acids commonly used are ____________________ and ____________________.
6. ____________________ acid is the only acid that will not damage chrome plating.
Now, look up the suggested answers in the Answer Key at the end of this section.
© 2005, Halliburton
8•7
Stimulation I
Chemical Stimulation
Unit B: Safety
• NO SMOKING around an acid tank. Tanks
containing acid or that have had acid in them
can have an explosive mixtures of gases and
liquids trapped inside. Crude oil vapors
mixed with air or hydrogen gas present in a
tank is also a possibility. Hydrochloric acid
reacts with steel to produce iron chloride and
hydrogen gas—a potentially explosive
situation.
Safety is a top priority in all job procedures.
Before pumping or handling acids or other
stimulation chemicals, you should study the
safety precautions given in the Chemical
Stimulation Manual excerpts on HalWorld.
This unit discusses several important
precautions to use when handling chemicals on
the job.
• Even though an acid tank is coated with a
sealant, there may be some exposed metal.
Hydrogen gas could be present.
Safety Precautions
Some critical safety precautions are as follows:
• Always add the water to the tank first and
then add the concentrated acid. Never add
water to acid or fill the tank with acid first.
This increases the risk of splashing and can
generate a large amount of heat.
• Always wear rubber gloves when working
around acid.
• Goggles should be worn due to possible leaks
in pump lines which may occur when
acidizing a well under pressure.
• Hydrogen, mixed with air in the ratio of one
part per 24 parts, is an explosive mixture.
For this reason, be aware of metal
connections when loading hoses. They could
strike the tank and ignite an explosion with
the smallest of sparks.
• Safety precautions should be taken when
handling hoses during the loading of trucks
or tanks or when disconnecting lines on a job.
Acid may be left in the hoses.
• It is always a good practice to notify
personnel on location when acid is being
used under pressure. All personnel should be
kept at a safe distance.
• Clothes contaminated with chemicals should
be removed and thoroughly washed before
wearing them again. Wash off any chemical
spills with water immediately.
• Acid pump trucks or transport trucks should
be furnished with first aid kits containing
soda (sodium bicarbonate) for acid burns.
Drivers and operators should ensure that it is
always accessible in case of emergency. A
solution of one teaspoonful of soda to a pint
of water should be kept for use in the eyes.
Dry soda can be applied directly to the skin
and then rinsed with water. DO NOT use dry
soda in the eyes.
• Wear a dust mask when handling powders.
Inhalation of any powdered material can be
irritating even if the chemical is not toxic.
The safety rules given here are a few of the rules
listed in the Chemical Stimulation excerpts on
HalWorld. Be sure to study the remaining rules.
An important section to be read in the safety
section of the Chemical Stimulation manual on
HalWorld is “Hydrogen Sulfide”.
NOTE: When washing eyes, use a gentle
flow of water when rinsing. You could
damage an eyeball or even wash it out of its
socket with a heavy stream of water.
© 2005, Halliburton
8•8
Stimulation I
Chemical Stimulation
Unit B Quiz
Fill in the blanks with one or more words to check your progress in Unit B.
1. Because of possible leaks in pump lines, ____________________ should be worn on chemical jobs.
2. First aid kits on acid trucks should contain ____________________ ____________________ that can
be dissolved in water for treating acid burns.
3. Dry soda can be applied directly to the ____________________ but not to ____________________.
4. The possible presence of ____________________ ____________________ is one reason smoking is
not allowed around an acid tank.
5. When working with acid and water, always put the ____________________ in first and then add the
____________________.
6. Wear a ____________________ ____________________ when handling powders.
Now, look up the suggested answers in the Answer Key at the end of this section.
© 2005, Halliburton
8•9
Stimulation I
Chemical Stimulation
Unit C: Reactions of Hydrochloric Acid
Reaction rates and products are important
considerations in acidizing. The various
characteristics can have an effect on the choice
of acid systems.
Concentrations of HCL acid solutions may range
from 1% to approximately 35% depending on
the use and requirements of the treatment. It
may be your responsibility to mix the various
acid blends required in stimulation treatment
applications. Tables like the following one have
been developed to assist you in determining the
proper amounts of concentrated acid and water
to use when mixing an acid solution (see Table
8.1). These tables are usually posted in acid
terminals.
HCL Reactions
When 1,000 gallons of 15% hydrochloric acid
solution reacts with calcium carbonate
(limestone), it will dissolve 10.9 cubic feet
(1843 lb) of the limestone. The products
resulting from “spending” the 15% HCL
solution upon the limestone will be:
Information for both 22 °Be and 20 °Be acid is
given in the table. Before using the table, find
out which of the two acid concentrations are
being stocked in the service center.
• 2050 pounds of calcium chloride (CaC12)
To illustrate the use of the table, assume that 20
°Be acid is stocked in the storage tanks and that
you need to mix 1000 gallons of 15% HCL acid
solution. You need to determine how much
water to add to the acid transport and how much
strong acid to add to the water to make the
solution.
• 40 gallons of water (H2O)
• 6620 cubic feet of carbon dioxide gas (CO2)
at standard conditions
The total volume occupied by 1000 gallons of
15% hydrochloric acid after the reaction is:
• 912 gallons of water pumped into formation
In Table 8.1, locate the heading “Gals 20 °Be
Acid & Water To Make 1000 Gals Acid.”
Under this heading observe that acid and water
amounts are given in separate columns. In the
extreme left-hand column “HCL% Acid” is
given. Under this column locate 15 % and move
horizontally across the chart. You will read 442
gallons of 20 °Be acid and 558 gallons of water
required to mix 1000 gallons of 15% HCL acid
solution.
• 40 gallons water made by chemical reaction
• 68 gallons of volume occupied by 2050
pounds of calcium chloride
• 1020 gallons total, assuming no volume is
occupied by the carbon dioxide gas or
diluted by formation brine
15% hydrochloric acid spent on limestone
becomes a 20.0% solution of calcium chloride
having a specific gravity of 1.175 and weighing
9.79 lb/gal.
© 2005, Halliburton
8 • 10
Stimulation I
Chemical Stimulation
Gals 22°Be Acid &
Water To Make 1000
Gal Acid
HCL
%
Acid
Gals 20°Be
Acid & Water To
Make 1000 Gal Acid
S. G.
Acid
Water
Acid
Water
Wt. In
lb/gal
Hydrostatic
psi/ft depth
1
1.005
2
1.010
3
1.015
4
1.020
5
1.025
6
1.030
7
1.035
8
1.040
9
1.045
10
1.050
11
1.055
12
1.060
13
1.065
14
1.070
15
1.075
16
1.080
17
1.085
18
1.090
19
1.095
20
1.100
21
1.105
22
1.110
23
1.116
24
1.122
25
1.127
26
1.132
27
1.136
28
1.141
29
1.146
30
1.153
31
1.158
31.45 1.160
32
1.163
33
1.168
34
1.173
35
1.178
35.2
1.179
Table 8.1
24
49
73
98
124
149
175
201
227
253
280
307
334
362
389
417
445
473
502
531
560
589
619
650
680
710
740
771
802
835
866
880
898
930
962
990
1000
976
951
927
902
876
851
825
799
773
747
720
693
666
638
611
583
555
527
498
469
440
411
381
350
320
290
260
229
198
165
134
120
102
70
38
10
--
28
55
83
112
140
169
199
228
258
288
318
349
379
410
442
473
505
538
570
603
636
669
703
738
772
806
840
875
910
948
983
1000
-----------
972
945
917
888
860
831
801
772
742
712
682
651
621
590
558
527
495
462
430
397
364
331
297
262
228
194
160
125
90
52
17
0
-----------
8.83
8.42
8.46
8.50
8.54
8.59
8.63
8.67
8.71
8.75
8.79
8.84
8.88
8.92
8.96
9.00
9.05
9.08
9.13
9.17
9.21
9.25
9.30
9.35
9.39
9.43
9.46
9.50
9.55
9.60
9.65
9.66
9.69
9.74
9.78
9.82
9.83
.435
.437
.439
.442
.444
.446
.448
.450
.452
.454
.457
.459
.461
.463
.465
.468
.470
.472
.474
.476
.478
.481
.484
.486
.488
.490
.492
.494
.497
.499
.502
.503
.504
.506
.508
.510
.510
© 2005, Halliburton
8 • 11
Eqiv.
Gal of
15% per
1000
gals
62
125
189
253
318
383
449
516
583
651
723
788
858
929
1000
1072
1144
1217
1290
1364
1439
1514
1592
1670
1747
1825
1902
1981
2061
2145
2226
2262
2308
2398
2481
2558
2573
Stimulation I
Chemical Stimulation
Unit C Quiz
Fill in the blanks with one or more words to check your progress in Unit C.
1. 1000 gallons of 15% hydrochloric acid will dissolve __________ pounds of limestone.
2. The products resulting from the “spending” of 15% HCL on limestone are __________ pounds of
calcium chloride, 40 ____________________ of ____________________, and __________ cubic
feet of ____________________ ____________________ gas at standard conditions.
3. The total volume of 1000 gals of 15% HCL after spending is ____________ gallons.
4. If you have 20 °Be acid, how much acid and water are required for 1000 gallons of 10% HCL?
__________ acid
__________ water
Now, look up the suggested answers in the Answer Key at the end of this section.
© 2005, Halliburton
8 • 12
Stimulation I
Chemical Stimulation
Unit D: Corrosion Inhibitors
and 85M, as well as the newer inhibitors HAIGE and OS. These inhibitors will not protect
such metals as aluminum and magnesium from
attack by hydrochloric acid. In addition,
galvanized coatings and chromium plating will
be attacked by inhibited hydrochloric acid. This
is true with these inhibitors and with all other
inhibitors, including competitive materials.
Some types of chrome and steel alloys can be
protected. Contact Duncan Research for further
information about these alloys.
Corrosion is defined as “the deterioration of a
substance (usually a metal) because of a reaction
with its environment.” In well stimulation, the
primary concern is the reaction of acids on the
well equipment, including tubular goods, during
acidizing treatments. This reaction can be
minimized by the use of corrosion inhibitors.
There is a dual purpose for adding inhibitors to
acid: the first is to protect our equipment and
the second is to protect the customer’s well
equipment. Several types of inhibitors are
available for use in the oilfield.
Acid corrosion inhibitors can be used up to
about 500°F. At temperatures above 275°F a
secondary component may need to be added.
Two such components are Halliburton Inhibitor
Intensifiers 124 and 500 (HII 124 and HII 500).
Corrosion of Metals
Several factors govern the degree of attack acid
has on steel. The primary factors are:
NOTE: When hydrochloric acid is mixed with
acetic or formic acid, the inhibitors used for
HCL are the inhibitors used in these mixtures.
• temperature
In general, the mixing procedures to follow
when mixing hydrochloric acid and organic
corrosion inhibitors together are:
• time of contact
• type of acid
• The required volume of water is first added
to the tank
• pressure
• type of steel
• The proper, measured volume of inhibitor is
added to the water and agitated
• ratio of volume of acid to exposed steel
surface area
• The concentrated acid from storage is
thoroughly mixed until uniformity is
obtained.
The longer acid is in contact with steel, the
greater the amount of steel dissolved. The
corrosion rate increases with increasing
temperatures. You must remember that
inhibitors do not stop corrosion; they only
decrease the rate of corrosion. This rate of
corrosion can be decrease to an acceptable level
if the proper inhibitor type and concentration are
used. Figure 8.1 shows the corrosion rate of
15% HCL with different concentrations of HAI85 on N-80 steel at 200 °F. Notice that the
Halliburton standard is a “Maximum Total
Corrosion Loss” of 0.05 lb/ft2 total steel
dissolved over the life of the test.
If the acid mixture requires additional additives,
they may be added to the water prior to final
agitation.
It is very important that the steps of addition of
material, agitation and blending be followed.
Even if each chemical has been dumped into the
tank, do not assume that uniform mixing will
occur while being moved to the location.
For more complete and detailed mixing
procedures, refer to the confidential field
bulletins for inhibitors found on HalWorld
Inhibitors being used presently in hydrochloric
acid are Halliburton Acid Inhibitors HAI-81M
© 2005, Halliburton
8 • 13
Stimulation I
Chemical Stimulation
procedures for MSA-II inhibitor are the same as
for other acid inhibitors. The Chemical
Stimulation Manual on HalWorld should be
used when determining amounts of MSA
inhibitor to use.
MSA Inhibitors
Organic acids such as formic and acetic require
an inhibitor other than HA1-81, 85M, or 72 E+.
MSA-II and the newer MSA-III inhibitors are
designed for use in these acids. MSA-II and
MSA-III inhibitors are not recommended for use
in hydrochloric acid solutions. Mixing
Other inhibitors are designed for many purposes.
You should become familiar with these
inhibitors and their functions.
Figure 8.1
© 2005, Halliburton
8 • 14
Stimulation I
Chemical Stimulation
Unit D Quiz
Fill in the blanks with one or more words or check the correct answer to check your progress in
Unit D.
1. The primary factors governing the degree of attack acid has on steel are:
________________________________________________
________________________________________________
________________________________________________
________________________________________________
________________________________________________
________________________________________________
2. ______ True
______ False
Inhibitors will stop corrosion.
3. Above 275° F, secondary components such as ____________________ and ____________________
may be needed for better corrosion protection.
4. ______ True
______False
Adequate mixing will occur if inhibitor is dumped into a transport and
the transport is driven over rough roads to the location.
5. The Halliburton standard limit for corrosion, over which more inhibitor should be added is
__________ lb/ft2
6. MSA Inhibitor is required when you use ____________________ acids.
Now, look up the suggested answers in the Answer Key.
© 2005, Halliburton
8 • 15
Stimulation I
Chemical Stimulation
Unit E: Carbonate Acidizing
maximum production is the result of minimum
damage.
Successful acidizing in limestone and dolomite
formations depends on a productive drainage
pattern formed by the action of the acid. One or
a combination of the following ways that acid
invades a formation accomplishes this:
(1) entering natural existing fractures
(2) entering cracks caused by hydraulic
fracturing
(3) entering the permeability of the formation
The extension of an effective drainage pattern
into a productive zone requires deep penetration
into some formations regardless of whether the
crevices exist naturally or are artificially made.
WELLBORE
Penetration is dependent upon the permeability,
porosity, oil saturation, the amount of productive
interval, the formation pressure and the depth of
the zone.
PRESSURE IN
FORMATION
Unplugged flow paths should exist from the
wellbore face to the outer limit of the formation.
Therefore, it is important that reaction products
and acid insoluble fines, which have been
dislodged by the chemical action on the
formation, be removed after acidizing.
PRESSURE DROP
ACROSS SKIN
Matrix Acidizing
WELLBORE
PRESSURE
Matrix acidizing consists of treating at a rate and
pressure low enough to avoid fracturing the
formation. This allows treatment of the natural
permeability, whether it is between the grains of
rock, in the vugular spaces of limestone or in
natural fractures.
Figure 8.2 - Schematic of a damaged well.
Top view with oil or gas flow. Side view with
pressure drop.
The skin factor can be reduced if near-wellbore
damage is removed or if a highly conductive
structure is placed in the formation. In either
case, the result is an increase in the production
rate of a well and/or the reduction of the
drawdown pressure differential. Decreased
drawdown can help prevent formation collapse in
weak formations, reduce water or gas coning,
minimize both organic and mineral scaling, and
Matrix acidizing enhances well productivity by
reducing the skin factor. Skin is the term used to
quantify damage that occurred to the formation
during drilling and completion. Damage occurs in
all stages of the life of a well, and it is
impossible to completely eliminate this
phenomenon. But, to produce hydrocarbons at
an economical and profitable rate, maximum
productivity is usually desired. In radial flow,
© 2005, Halliburton
SKIN OR ZONE
OF DAMAGE
8 • 16
Stimulation I
Chemical Stimulation
help ensure that a greater percentage of the
completed interval contributes to production.
Fracture Acidizing
Matrix acidizing should be considered when
damage is present or when a water zone or gas
cap is close and fracturing could result in high
water production or excessive gas/oil ratio.
Most limestone and dolomite formations have
low permeability. Acid injected into these low
permeability formations, even at moderate rates,
usually result in a fracture type acid treatment.
Fracture Acidizing is the most widely used
treatment for limestone and dolomite
formations. The success of a fracture acidizing
treatment depends upon the ability to create a
conductive fracture with enough length and
height. Most fractures are vertical, and the
productivity should increase as the vertical
fracture height approaches the formation height.
The productivity should also increase as the
fracture length approaches the drainage radius of
the well. Of course, the fracture must have
adequate flow capacity so that produced fluids
will have a passageway from the formation into
the well bore.
Expected Results
Results from matrix acidizing depend upon the
type of permeability and porosity present and the
presence and extent of any formation damage.
For example, assume that flow from a producing
limestone or dolomite is radial and the
permeability near the wellbore is the same as it
is deep in the formation (no damage). In this
case, an increase in the permeability due to
acidizing in the immediate vicinity of the well
will give a relatively small increase in the
production capacity of the well. In fact, if the
acid completely dissolves the limestone or
dolomite up to a radius of five feet, the
production capacity of the well can be increased
by only 65% maximum. However, if the well is
partially plugged, and the damage can be
removed to a radius of five feet around the well
bore, the production capacity can increase by as
much as 350%.
To achieve good fracture extension and adequate
flow capacity, an acid that has low fluid loss and
produces good flow capacity should be used.
Formation Core and Fluid
Testing
The following tests performed on formation core
samples are useful in planning acid treatments.
Types of Porosity
In the fluid loss test, fluid is forced through a
core plug cut from a submitted core sample. A
differential pressure of 1,000 psi is used, and the
test temperature duplicates the bottom hole
temperature of the well. Various types and
quantities of fluid loss additives are tried in
order to establish the most effective additive to
use in the preflush and the acid. The fluid
efficiency of the acid and water preflush can be
determined from these tests. These fluid
efficiencies are used in calculating the created
fracture area.
When the porosity is intergranular (between
grains) and the formation is the same all over
(homogeneous), then matrix acidizing of this
type of formation might produce approximately
a 60% increase in production if no damage
exists. Should damage exist, much larger
production increases could be expected.
If the porosity is vugular (large holes), the
formation is homogeneous, and no damage
exists, then production increases in the 100150% range are possible. If damage exists, then
greater production increases can be expected.
If there are naturally occurring fractures in either
a vugular or intergranular type formation, then
production increases of several hundred percent
might be possible.
© 2005, Halliburton
8 • 17
A rotating disc reaction rate apparatus is used to
determine the true surface reaction rate and
order of reaction of the formation to be acidized.
Another test involves determining fracture flow
capacity from acid etched cores. On of the
differences between fracture acidizing and
Stimulation I
Chemical Stimulation
conventional water frac or oil fracs is that
usually no propping agent is used. The acid
produces flow capacity by removing limestone
or dolomite from the fracture faces. However,
laboratory tests indicate that certain types and
concentrations of acid can create more fracture
flow capacity.
are placed together, and pressure is applied. The
resulting fracture flow capacity can then be
measured.
The etching time is also important. Laboratory
etching tests determine the etching time and type
acid which produce the maximum flow capacity.
These tests are conducted by placing two core
faces in a chamber approximately 0.1 inch apart.
Acid flows radially across this simulated
fracture at 1,000 psi pressure and at simulated
bottom hole temperature. After a certain etching
time, the cores are removed, the etched surfaces
There are some formations in which fracture
flow capacity cannot be created with acid, either
because the formation etches smoothly or
because large quantities of insoluble fines plug
the channels. In these formations, a SUPRA
technique or a conventional fracturing solution
carrying a propping agent should be considered.
The acid etching tests can be used to determine
the feasibility of fracture acid stimulation and
the best type acid to use. Figure 8.3 shows a
decision tree to help determine what type of
treatment to perform.
Figure 8.3 - Acid Treatment Decision Flowchart
© 2005, Halliburton
8 • 18
Stimulation I
Fracture Acidizing Plan
Calculations
For a successful acid treatment, the acid solution
must be compatible with the produced fluids.
Emulsion tests should always be run with the
produced fluids and the treating solution. These
tests are run by mixing equal volumes of the
treating solution and the produced oil with high
shear. The time and amount of separation are
noted. Complete separation of the mixture
within ten to fifteen minutes is desirable. The
tests are run with both live and spent acid
because the fines released from some formations
tend to stabilize emulsions. The acid used in the
emulsion tests should contain all of the additives
that are going to be used in the job since many
of these additives affect the emulsion tests.
The information obtained in the tests described,
along with certain well and formation data are
used in computerized design programs. The
calculations in Halliburton’s Acid Design
Program have been incorporated into FracPro
PT, a 3-dimensional fracture simulator which
can determine the conductive fracture length and
the productivity increases that are possible. If
cores are not available, a treatment design can be
run using information determined previously on
cores from the same formation and same area.
Acid can cause some of the asphaltene
components of the crude to fall out of solution.
These solids are commonly called “acid sludge.”
A sludge test should be run to see if anti-sludge
agents are needed in the acid.
Acid Systems
In recent years, Halliburton has made an effort
to simplify it’s terminology in describing the
wide variety of acid systems and additives. The
Carbonate 20/20 program helps fill a void in the
oil industry created by the lack of personnel that
can effectively design acid treatments. Several
standard acid blends resulted from the Carbonate
20/20 initiative.
Tubing Movement Program
The Tubing Movement Program (TMP) helps
predict the amount of tubing movement that can
occur because of the high pump rates and fluid
volumes. This tubing movement is primarily
caused by changes in the tubing through the
cooling effects from the pumped fluids, from the
pressures exerted by fluids in the tubing and
annulus, and from the friction effect of these
pumped fluids. One of the main advantages of
the program is that it uses bottom hole treating
pressure as a starting value along with a specific
pump rate. A computer print-out includes:
Carbonate Completion Acid
Carbonate Completion Acid (CCA) minimizes
compatibility problems, especially for reservoirs
containing asphaltene crudes. CCA uses HAIGE corrosion inhibitor which is compatible with
non-ionic and anionic surfactants.
Although the CCA system is primarily used for
acidizing carbonate reservoirs that contain
asphaltene crude, it can also be used on “sour”
wells (wells containing hydrogen sulfide) if
sulfide scavenger is added and on sweet wells if
ferric iron control is used. Because the inhibitor
and antisludging agent are compatible, they can
prevent sludging without compromising
corrosion protection. For effective corrosion
inhibition, the upper temperature limit of the
CCA system is approximately 200°F in 15%
HCL. Depending on acid concentration, contact
time, and metal type, this temperature limit can
be higher or lower.
• surface injection pressure
• total tubing movement, which includes
• piston effect
• ballooning effect
• frictional effect
• buckling effect
• thermal effect
• the amount of force required to be exerted in
order to overcome these five effects
© 2005, Halliburton
8 • 19
Stimulation I
Chemical Stimulation
Carbonate Stimulation Acid
Zonal Coverage Acid
The Carbonate Stimulation Acid (CSA) system
is used in carbonate formations for stimulating
production. Operators can use CSA to stimulate
carbonate formations by fracture acidizing or
matrix acidizing. Regardless of the approach, the
acid should be viscous to promote effective
stimulation.
The Zonal Coverage Acid (ZCA) System is a
crosslinked acidizing fluid system that can be
used in carbonates for fracture acidizing and for
diversion during matrix acidizing. The use of
crosslinked acidizing fluids in the past was
limited. The high fluid viscosity required during
pumping increased frictional pressures, which
required greater pumping horsepower. In
addition, obtaining a live-acid crosslinked fluid
was an expensive process. In many cases, fully
crosslinked acids were not necessary to retard
the reaction of HCL on carbonates; viscosifying
the acid provided ample retardation. In such
treatments, however, much of the acid was lost
as a result of leakoff through wormholes (Figure
8.4).
Gelling agents made from synthetic polymers
are the most useful viscosifiers for acidizing
carbonate formations. These materials resist acid
hydrolysis (breaking) over a wide range of
temperatures. Currently, Halliburton offers four
gelling agents made from synthetic polymers:
SGA-HT, SGA-II, SGA-III and SGA-IV.
The most effective gelling agent for acidizing
carbonate formations depends on the agent's
working temperature range, ease of mixing,
compatibility with other additives, and control
of reactivity. Based on these characteristics,
SGA-HT is usually the best gelling agent to use
for acidizing carbonate formations. However,
this viscosifier is also significantly more
expensive than SGA-II, III and IV. SGA-II and
SGA-III can be used at lower temperatures and
SGA-IV is the only gelling agent compatible
with sulfide scavengers. Table 8.2 presents
various properties of these three gelling agents.
Product
Viscosity
170 S-1
150°F
2% Conc.
Temp Limit
(°F)
Charge
Ability
to
crosslink
SGA-HT
27 cp
400-425
+
No
SGA-II
19 cp
200-225
-
Yes
SGA-III
39 cp
300-325
+
Yes*
SGA-IV
33 cp
200-225
+
Yes**
Table 8.2 – Acid Gelling Agents
*SGA-III must be premixed in HCL for 2 to 4
hours to develop adequate crosslink sites.
**SGA IV is the only acid gelling agent
compatible with SCA-130 sulfide scavenger.
© 2005, Halliburton
Figure 8.4 – Leakoff due to wormhole
growth during acid fracturing
Zonal Coverage Acid (ZCA) system is an insitu crosslinked gelled acid system. When this
system is used, fluid loss can be controlled as
the acid leaks off through wormholes and
spends. Once the acid is nearly spent, the system
crosslinks, blocking wormholes and preventing
further loss of acid from the fracture face. The
system will not break until the acid is
completely spent.
SGA-II, III or IV can be used as a gelling agent
in the ZCA system. SGA-III must be premixed
in acid for 2 to 4 hours to develop adequate
crosslink sites for use in the ZCA system.
8 • 20
Stimulation I
Chemical Stimulation
Therefore, if planning to run ZCA system fluids
on-the-fly, use SGA-II or IV gelling agents.
Handbook can be used when you design an
FRA treatment.
Carbonate Emulsion Acid
Hot Rock Acid
Carbonate Emulsion Acid (CEA) is an
emulsified acid system used in carbonate
reservoir stimulation jobs that require retarded
acid reaction rates. The upper temperature limit
of the system is approximately 400°F. In
fracture acidizing applications, formations that
produce heavy crude oils with high quantities of
asphaltenes tend to respond best to CEA.
The Hot Rock Acid (HRA) system is a totally
organic acid system with a dissolving power
equal to 15% HCL. HRA is an acid system
specifically for high temperature wells. It
consists of both acetic and formic acids set at
different ratios to eliminate secondary
precipitation problems and maintain maximum
dissolving power. The Hot Rock Acid system
increases stimulation effectiveness and reduces
corrosion rates. Specifically, it allows extended
reaction times, provides built-in iron control,
and enhances the performance of acid gelling
agents. Because of the reduced interfacial
tension the service provides, emulsion and
sludging problems are less likely.
Because of its excellent acid retardation
properties, the system has also been successfully
used in higher-temperature matrix acidizing
applications. Under high-temperature conditions,
the CEA system allows live acid to penetrate
deeper into the formation matrix than other acid
formulations. As a result, wormholing is
improved.
By volume, 70% of the CEA system consists of
22% hydrochloric acid as the internal phase and
30% of No. 2 diesel as the external phase of the
emulsion. The CEA system is formed through
the use of AF-61 emulsifier along with a
corrosion inhibitor.
Fines Recovery Acid
Additional Reference
Fines Recovery Acid (FRA) is an energized acid
system for stimulating carbonate formations
with bottomhole static temperatures (BHST) up
to 150°F. The energized phase of FRA is
For more detailed information and mixing
procedures, consult the Carbonate 20/20
technical bulletins on HalWorld.
70% nitrogen. The acid is usually 20%
HCL with a gelling agent and inhibitor. In
addition to demonstrating low liquid
concentrations and good fluid loss, the FRA
system can also be used in low-pressure,
liquid-sensitive wells that normally produce
fines during acidizing, or wells that have
fluid and fines recovery problems.
Preflushes
In fracture acidizing, good productivity can be
obtained if adequate fracture geometry can be
created that has enough conductivity. The
fracture geometry is determined by the fluid
properties such as fluid loss, fluid viscosity and
the injection rate. However, the conductivity of
the fracture is a function of the amount and
pattern of rock removed from the fracture faces,
not from acid leaking off into the formation.
Under matrix acidizing conditions, the FRA
system can be used to divert in long
horizontal open hole sections.
STIMWIN, STIM2001, FOAMUP,
FracproPT and the Halliburton Nitrogen
© 2005, Halliburton
Although the base acid cost for the Hot Rock
Acid system is about twice that of HCL, the
reduction in corrosion inhibitor loading and the
reduced gelling agent requirement generally
result in lower overall treatment costs. In
addition to the two acids, the system includes
MSA-II inhibitor, SGA-HT gelling agent and an
appropriate surfactant. Iron-control additives can
be used but are not necessarily required.
8 • 21
Stimulation I
Chemical Stimulation
The distance that a conductive fracture can be
created is dependent upon the reaction rate of
the acid as well as the fluid properties. One
method of obtaining slower reaction rates is to
use water preflushes to cool the fracture faces.
Preflushes also produce wider fractures for the
acid, which improves the rock surface area to
acid volume ratio. This gives better penetration
distance of live acid. Acid fluid loss is also
decreased by the use of water preflushes.
natural fractures, and fluid-loss control is
reestablished.
SUPRA CE (Conductivity
Enhancement)
When using the SUPRA CE technique, service
operators pump a viscous pad fluid ahead of the
acid and behind an optional nonviscous, cool
down prepad. As the viscous pad is pumped, it
generates fracture geometry. Because the acid
that follows it is less viscous, it “fingers”
through the viscous pad. This fingering process
limits the acid contact to the formation face,
which creates etched and nonetched areas. This
process results in longer acid penetration
distance and possibly more effective
conductivity at a greater distance along the
induced fracture.
A viscous preflush can be used like a nonviscous preflush. The increased viscosity has
the added advantage of creating a wider and
possibly higher fracture.
Acid Placement Techniques
The SUPRA (sustained-production acidizing)
techniques are another result of the Carbonate
20/20 initiative. They detail the different
methods that can be used under various well
conditions to generate the optimum conductive
geometry in the reservoir being treated.
SUPRA FLC (Fluid-Loss Control)
SUPRA FLC controls acid fluid-loss in induced
and natural fractures. In rock matrix or natural
fracture systems, acid leakoff must be controlled
so that live acid will remain within the fracture
and generate effective etched fracture length.
Under some conditions, Carbonate 20/20
treating fluids provide fluid-loss control. Under
excessive fluid-loss conditions, some additional
fluid-loss material may be required in addition
to alternating phases of acid and nonacid fluids.
The acid provides conductivity, and the nonacid
fluid (containing fluid-loss additive) establishes
or re-establishes fluid-loss control.
Figure 8.5 - SUPRA CE Technique
SUPRA EHC (Etched Height Control)
The nonacid phase also acts as an acid extender,
allowing a sufficient volume of acid to penetrate
the required distance while reducing the volume
of acid necessary for that distance. Phases can be
alternated at any time, depending on the treating
conditions. The acid leaks off and forms
wormholes or goes into natural fracture systems.
The nonacid phase (containing fluid-loss
additives) sands off and seals up wormholes or
© 2005, Halliburton
8 • 22
The SUPRA EHC technique uses fluid density
differences to control fluid placement in certain
sections of an induced vertical fracture. This
technique can place acid in areas of a fracture
that do not contain water or possibly a gas cap.
Figure 8.6 shows the fracture-acidizing process
including SUPRA EHC. Advantages of the
SUPRA EHC system are that it prevents the acid
treatment from entering unwanted zones such as
Stimulation I
Chemical Stimulation
water-producing intervals and gas caps, and that
it uses less acid.
Closed-Fracture Acidizing (CFA)
With the aid of nitrogen, many heavier fluids
can be lightened by foaming (gas content greater
than 55%) or commingling (gas content less
than 55%) gas in the fluid. Even with the best
engineering and design, this treatment may not
always work.
The closed-fracture acidizing (CFA) technique
reopens previously created fracture systems with
a prepad fluid pumped at high rates. The
fractures are then allowed to close naturally, or
part of the prepad is flowed back to force the
fractures to close. Next, acid and any necessary
additives and diverters are pumped below
fracturing pressure. This technique can also be
used immediately after a fracture acidizing
treatment performed for enhanced etched
conductivity.
For more information on these acid placement
techniques, consult the Carbonate 20/20 best
practices page on HalWorld.
Figure 8.6 - Fracture-Acidizing Process
Including SUPRA EHC
© 2005, Halliburton
8 • 23
Stimulation I
Chemical Stimulation
Unit E Quiz
Fill in the blanks with one or more words to check your progress in Unit E.
1. Matrix acidizing enhances well productivity by reducing the ____________________ factor.
2. Matrix acidizing requires that rates and pressures be controlled so that ____________________ does
not occur.
3. Decreased well pressure drawdown can help prevent formation ____________________ in weak
formations, reduce water or gas ____________________, minimize both organic and mineral
____________________.
4. The most widely used treatment for limestone and dolomite is _____________________
____________________.
5. One method of obtaining slower reaction rates is to use water _____________________ to
____________________ the fracture faces.
6. _____ True ______ False
Fracture conductivity is generated by acid leaking off into the
formation.
7. Which Carbonate 20/20 acid system is used when asphaltenes are a problem?
_____ a)
Carbonate Stimulation Acid
_____ b)
Carbonate Completion Acid
_____c)
Zonal Coverage Acid
_____d)
Carbonate Emulsion Acid
8. Which acid system uses a crosslinked gel to control leakoff?
_____a)
Carbonate Stimulation Acid
_____b)
Carbonate Completion Acid
_____c)
Zonal Coverage Acid
_____d)
Carbonate Emulsion Acid
9. What does SUPRA stand for?
____________________-____________________ ____________________
Now, look up the suggested answers in the Answer Key.
© 2005, Halliburton
8 • 24
Stimulation I
Chemical Stimulation
Unit F: Sandstone Acidizing
reaction products and also has a significant
effect upon the reaction rate.
Basically, two types of acids are used in
sandstone acidizing: hydrochloric acid alone and
hydrofluoric-hydrochloric acid mixtures.
Normally, these treatments are used to stimulate
near the wellbore (maximum 5-6 feet out).
Damage Removal
These treatments are done at rates that will not
fracture the formation. They can be very
effective in removing damage near the wellbore.
Hydrochloric Acid
Even though hydrochloric acid will not dissolve
sand or clays, it is still useful in acidizing
sandstone formations. It will dissolve any
carbonates that might be present in the formation
and will also partially dehydrate water-swollen
clays.
In sandstone stimulation, hydrochloric acid is
usually combined with Morflo III to produce
MCA (Mud Cleanout Acid). The hydrochloric
acid in MCA shrinks swollen clay particles.
Morflo III disperses clays and acts as a
surfactant to aid in emulsion prevention and
faster cleanup.
The hydrochloric-hydrofluoric acid mixture (HF
Acid) has application in mud-or clay-damaged
sandstone formations. There are two
fundamental types of clay damage in sandstone.
One type is mud damage where bentonite
drilling mud particles have coated the formation
face or have invaded the formation. This type of
damage is considered to be very shallow,
possibly only an inch or so deep.
The second type results from naturally occurring
clays that have either migrated toward the
wellbore and are plugging flow channels or have
become hydrated and swollen due to contact by
fresh water. This type of damage is deeper into
the formation than mud damage.
Reaction Rates
The Speed with which hydrofluoric acid reacts
upon sandstone is affected by
Hydrofluoric Acid
• physical and chemical composition of the
formation
In contrast to hydrochloric acid, hydrofluoric
acid does have the ability to dissolve silica
(sand) or silicates such as clays, silt, shale and
feldspars. Since bentonite is a silicate, it can
also be dissolved by hydrofluoric acid.
Sandstone formations having permeability
damage due to clay migration or benetonite
drilling mud can usually be helped by a
hydrofluoric acid treatment.
• temperature
• surface area of rock exposed to a particular
volume of acid
• concentration of excess hydrochloric acid
Sandstone formations are basically composed of
quartz, with some limestone, dolomite,
feldspars, and several clay minerals.
Hydrofluoric-hydrochloric acid mixtures react
with these materials at varying rates. Therefore,
the reaction rates of the HF Acid mixtures will
vary considerably with the composition of the
formation. The physical distribution of the acid
Hydrofluoric acid is usually pumped as a
hydrochloric-hydrofluoric acid mixture (HF
Acid) with the hydrofluoric acid being obtained
from the reaction of hydrochloric acid on
ammonium bifluoride. Hydrochloric acid
increases the solubility of some of the secondary
© 2005, Halliburton
8 • 25
Stimulation I
Chemical Stimulation
soluble material throughout the formation also
influences reaction rate.
Sandstone-2000 TM
Another factor greatly influencing the rate of
reaction is bottom-hole temperature. The higher
the temperature, the more rapid is the reaction.
For example, laboratory data taken from tests
reacting 25 ml of acid on 4.0 gm of sand reveal
that 33.6 lb of 20-40 mesh Ottawa sand would
be dissolved by 1,000 gallons of a 3% HF-12%
HCL acid mixture in eight hours at 75°F.
However, at 200°F, 1,000 gallons of the same
acid mixture would dissolve 43.1 lb of the same
sand in only one hour.
Sandstone acidizing technology has improved
significantly in recent years as a result of field
analysis, fundamental research and applied
research. Traditional sandstone acidizing
treatments were performed by pumping a
standard blend of 3% HF and 12% HCL acids.
These treatments often had minimal success and
sometimes actually damaged the well further.
Older theories regarding reactions occurring
between the acid and the formation proved to be
inaccurate in 1984 when samples from a Gulf
Coast well were obtained after sandstone
acidization. Based on this research, the
Sandstone 2000TM acidizing processes were
developed. Like the Carbonate 20/20 initiative,
Sandstone 2000TM created a set of “best
practices” to help improve Halliburton’s
sandstone acidizing success rate.
The surface area of material exposed to the acid
also influences the rate of the reaction. This is
probably the primary reason that hydrofluoric
acid dissolves clay minerals more rapidly than it
does quartz. As shown above, 1,000 gallons of
3% HCL will dissolve 33.6 lb of 20-40 mesh
sand in eight hours at 75°F. However, under the
same test conditions, 1,000 gallons of the same
acid will dissolve 50.7 lb of silica flour in only
30 minutes.
Formation Conditioning
Further data show that 72.6 lb of silica flour
containing 5% bentonite will be dissolved by
1,000 gallons of 3% HF-12% HCL in 30
minutes at 75°F. These examples illustrate the
influence of the exposed surface area on the rate
of the reaction. Under reservoir conditions the
surface area-to-volume ratio will be much
greater than that of any of these examples. As a
result, the reaction in the formation will be more
rapid.
Treatment of a well before sandstone acidizing
can greatly increase the success rate of this type
of treatment. Formation conditioning design
depends on the presence of key minerals. Proper
use of a formation conditioner or a combination
of conditioners before treatment with HF acids is
critical to the success of the treatment.
Clays
Therefore, the influence of exposed surface area
of rock on the reaction rate cannot be overemphasized.
Clays were previously thought to be of minor
consequence. However, recent work has shown
that the impact of clays can be dramatic for
brines undergoing deep matrix invasion in
sandstones. Table 8.3 shows some mineralogies
that could cause problems.
The importance of the concentration of excess
hydrochloric acid can be illustrated with the
following examples. Using calculations from
laboratory tests conducted by reacting 25 ml of
acid on 4.0 gm of sand for 30 minutes at 75°F,
1,000 gallons of 3% HF-0% HCL will dissolve
27.1 lb of silica flour containing 5% clay. The
same volume of 3% HF-12% HCL and 3% HF20% HCL will dissolve 72.6 lb and 90.8 lb
respectively.
© 2005, Halliburton
8 • 26
Stimulation I
Chemical Stimulation
Mineral
Feldspars
Carbonate
Illite
Kaolinite
Smectite
Mixed-Layer Clay
Chlorite
Mica
Zeolite
The CLA-STA additives described in Section 6
can also be used to enhance clay stabilization.
Problem
Contains sodium and
potassium. Fluosilicate
precipitation and K-Spars can
create major problems.
Consumes HCL and can cause
precipitation of fluosilicates and
aluminum from spent HF.
Can cause fines migration
problems, is ion exchanging,
and contains potassium which
can cause fluosilicate
precipitation from spent HF.
Can cause fines migration
problems and disperses in fresh
water and causes plugging.
Is ion exchanging and swells in
fresh water.
Is ion exchanging, swells in
fresh water, and frequently
contains potassium which can
cause fluosilicate precipitation
from spent HF.
Is ion exchanging and is
unstable in HCL.
Is ion exchanging, is unstable in
HCL, and contains potassium
which can cause fluosilicate
precipitation from spent HF.
Is ion exchanging, is unstable in
HCL, and occasionally contains
sodium which can cause
fluosilicate precipitation from
spent HF
HCL Sensitivity
Many formations are “HCL-sensitive;”
formation minerals decompose when contacted
by HCL. During this process, metal ions such as
iron, aluminum, calcium, and magnesium are
dissolved from the mineral, leaving an insoluble
silica gel mass that can be extremely damaging.
HCL-sensitive minerals include zeolites and
chlorite. However, research has shown than all
clays have a temperature above which they are
unstable. When conditions make formation
minerals highly unstable, only organic acidbased systems should be used.
CLAY-SAFE
Despite the sensitivity of clays to HCL, they are
stable in acetic acid and fairly stable in formic
acid. Unfortunately, both of these acids are
similar to fresh water in the presence of watersensitive clays. Substituting acetic acid (MSA)
for CLAYFIX is not a good alternative, since
MSA does not exchange ions with the clays or
prevent clay swelling. MSA is not an equivalent
substitute for HCL because it does not dissolve
iron scales and is slow to dissolve carbonates.
However, use of CLAY-SAFE conditioners
should provide sufficient ion ex-change to help:
Table 8.3 – Problem Formation Mineralogy
CLAYFIX
When ion exchange occurs, the cations naturally
present on the surfaces of the clays are replaced
or exchanged with ions from the invading brine.
For example, 7% potassium chloride brine
(KCl), after exchanging ions with the formation,
becomes approximately 5% sodium chloride
(salt). Because of this exchange it is important
that the transformed brine should also be
compatible with the formation.
•
prevent precipitates in the HF/HCL process,
•
control clay swelling, and
•
stabilize the clay to sandstone acidization.
Their recommended uses are given in Table 8.4,
but the Sandstone Stimulation Process section
on HalWorld should be consulted for proper use
of these fluids.
The most effective brine for sandstone acidizing
is ammonium chloride (NH4CL), also called
CLAYFIX. CLAYFIX 5 (5% NH4CL) provides
sufficient ion exchange and maintains enough
salt concentration to prevent clay swelling
before and after ion exchange.
© 2005, Halliburton
8 • 27
Stimulation I
Chemical Stimulation
Fluid System
Mud Cleanout
Mud-Flush
N-Ver-Sperse
Wellbore Conditioning
Paragon or other organic
solvents
HCL for pickling
When to Use
Whole water-based mud
losses
Whole oil-based mud losses
Asphaltene/paraffin problems,
heavy oils, pipe dope
Removing iron scales and
preventing them from entering
the formation
Oil Well Conditioning
Gidley's CO2 Conditioner
Emulsion problems, terminal
upsets, improves acid
penetration into oil zone
Matrix Conditioning
CLAYFIX 5
High ion-exchanging clays
5-15% HCL
Carbonate removal, ion
exchange, removal of polymer
damage
CLAY-SAFE 5
*See note below.
Carbonate removal, ion
exchange for HCL-sensitive
mineralogy
CLAY-SAFE H
HCL-sensitive mineralogy, but
it requires removal of polymer
damage (K-Max, HEC, etc.) or
high carbonate levels.
CLAY-SAFE F
*See note below.
HCL-sensitive mineralogy, but
it requires increased
carbonate dissolving power
without increased volume.
See note below.
*Note: MSA II Inhibitor and 5% NH4Cl are not compatible when
the MSA II Inhibitor concentration is above 1%. Below 1% MSA II
Inhibitor, dispersing agents may be required.
Table 8.4 – Formation Conditioning System
Carbonates
Sandstone formations containing greater than
5% carbonates are prone to matrix precipitation
of complex aluminum fluorides as spent HF
flows across the carbonates. The solution to this
problem requires
•
deep removal of the carbonate with large
preflushes of HCL or
•
the use of an additive that prevents
precipitation.
© 2005, Halliburton
For example, 50 gal/ft (gallons per foot of
formation height) of 15% HCL preflush in a
sandstone containing only 5% calcite will
remove the calcite in a radius of about 2 ft from
the wellbore. If spent HF follows, aluminum
fluoride precipitation will begin 2 ft from the
wellbore.
Gidley’s CO2 Conditioner
Carbon dioxide preflushes have successfully
prevented fluid compatibility and emulsion
problems after sandstone acidizing treatments
and have improved the HF treatment response.
One operating company’s study revealed that
oil-wet particulates (silica and fines) stabilized
emulsions. These particles were precipitated
from HF acid reacting with the formation in the
presence of hydrocarbons, such as crude oil and
xylene. The solution is in Gidley’s CO2
Conditioner, a Halliburton-exclusive process
that removes the hydrocarbons from the nearwellbore area. The carbon dioxide treatment
uses 100 to 200 gal/ft of CO2 under miscible
(easily mixed) conditions to displace the oil
away from the matrix in the near-wellbore area.
Displacing the hydrocarbons allows better HF
invasion of the matrix and prevents emulsions
from forming.
The CO2 can also be used throughout the acid
stages to provide enhanced energy for cleanup.
Some oils form asphaltene precipitation easily
and other oils have minimal miscibility with
CO2 under reservoir conditions. Both of these
conditions can be at least partially eliminated
with a xylene preflush ahead of the Gidley’s
CO2 Conditioner.
Secondary Precipitation
When hydrofluoric acid reacts with either
silicates (clay minerals) or silica (quartz), one of
the reaction products is fluosilicic acid. This
acid will react with sodium or potassium to form
sodium fluosilicate or potassium fluosilicate.
The sodium and potassium fluosilicates have
very low solubility, and precipitation can occur.
This can happen if the hydrofluoric acid contains
8 • 28
Stimulation I
Chemical Stimulation
• Contains ALCHEK to prevent secondary
precipitation of aluminum. This is
particularly important when the mineralogy
is unknown or the formation contains high
carbonate streaks or more than 5%
carbonates.
sodium or potassium, or if the spent or partially
spent acid becomes mixed with solutions
containing these chemicals. This means that salt
water should not be used as mixing water for the
acid or for displacing the acid. The acid should
not be weighted with sodium chloride or
calcium chloride. When calcium chloride is
added to hydrofluoric acid, calcium fluoride will
precipitate immediately. Diverting aids such as
rock salt should not be used because of
secondary precipitates. If additional weight is
necessary, it is possible to use ammonium
chloride as the weighting agent.
• Aids in iron control, in most cases
eliminating the need for other iron control
additives such as Fe-2 (citric acid) and Fe1A (acetic acid).
• Contains a penetrating agent to help acid
contact damage.
The overall advantage of Sandstone Completion
Acid is that it provides the customer with
maximum dissolving power while maintaining
compatibility which is particularly important
when the mineralogy is unknown. The 1.5% HF
is the maximum HF concentration recommended
in most sandstone matrix acidizing treatments.
Acid Systems
Silica Scale Acid
Silica Scale Acid is the old regular HF or mud
acid (12% HCL-3% HF). It is effective at
removing damage, but its high HF
concentrations almost invariably result in
secondary precipitation very near the wellbore
resulting in failures or limited, short-term
successes. Therefore, this system is
recommended for use only when the mineralogy
shows there are essentially no clays and 100%
quartz, or in geothermal wells.
Fines Control Acid
RHF (Retarded HF Acid) is an acid system that
has proven successful. The patented system has
been modified slightly and renamed Fines
Control Acid.
Sandstone Completion Acid
Sandstone Completion Acid consists of 13.5%
HCL-1.5% HF, Pen-88 as penetrating agent, and
5% ALCHEK to prevent precipitation of
aluminum in the formation and in the wellbore
(alumino-silicate scaling). This fluid is
compatible with a majority of formations and
was particularly designed for the cases where the
formation mineralogy is unknown or uncertain.
The primary advantages of sandstone
completion acid are:
• Contains high HCL-HF ratio to provide
compatibility with most formation
mineralogies. Exceptions include formations
high in feldspars, particularly at
temperatures below 200°F and formations
containing "HCL-sensitive" minerals.
© 2005, Halliburton
Conventional matrix acidizing with hydrofluoric
acid is only effective for removing shallow clay
damage 1 or 2 in. from the wellbore. Fines
Control Acid is a retarded hydrofluoric acid
system designed for treating sandstone
formations that have been damaged from the
migration and/or swelling of silica, feldspars,
and clays up to 2 to 6 in. from the wellbore.
Formations with significant Kaolinite and /or
illite are particularly sensitive to this type of
damage. The fluoride content of Fines Control
Acid is equivalent to the fluoride content of
1.5% HF, but its effective dissolving power is
equivalent to 1.1% HF. However, because of its
retarded nature in its reactions with sand, it is as
effective in removing clay damage as 1.5% HF.
Fines Control Acid can also be effective in
formations that appear to be HCL-sensitive. In
these cases CLAY-SAFE 5 Conditioner can be
used followed by Fines Control Acid. Formation
minerals do not show acid sensitivity when
8 • 29
Stimulation I
Chemical Stimulation
treated in this manner, as discussed in an earlier
section on HCL-sensitivity.
overall content is greater then 10%. Since the
fluosilicates are less soluble at lower
temperatures, K-spar Acid should also be used
in most formations containing any significant
sodium feldspars below 175°F. In formations
containing high concentrations of potassium
feldspars below 200°F, lower HF concentrations
are suggested. If fluosilicate precipitation cannot
be avoided, an HCL overflush should be used to
help re-dissolve the precipitate.
The primary advantages of fines control acid
are:
• Deeper penetration of live HF into the
formation.
• Retarded reaction with sand and silica to
promote deep damage removal and improve
compatibility with feldspar-containing
formations.
Cla-Sta FS is included to control fines migration
associated with illite or mixed-layer clays. These
clays are almost always present when potassium
feldspar is a dominant mineral and are very
susceptible to fines migration during a
stimulation treatment. K-Spar Acid will prevent
this migration. If fines migration is the source of
damage, Fine Control Acid is recommended.
The HF fluid treatment design could consist of
50 gal/ft of K-spar Acid followed by 200 gal/ft
of Fines Control Acid.
• Minimized damage to formation
consolidation - it reacts less with the sand
that holds the formation together.
• Fe-1A for iron control and preventing
aluminum scaling.
• Penetrating agent to help acid contact
damage.
• Clay stabilizer to control fines migration
during and following the treatment.
The primary advantages of K-Spar acid are:
• Temperature limitation only because of
corrosion inhibitor and formation mineral
stability, as in non-retarded HF systems.
• Is compatible with formations containing
significant feldspar and/or illite minerals
Higher volumes of Fines Control Acid should be
used where deep, severe damage has occurred. A
lower volume of overflush can be used when the
well is predicted to clean up rapidly. When
difficulty in cleaning up the well is anticipated,
the large volume of overflush should be used to
push the HF-containing fluids far from the
wellbore. Since Fines Control Acid does not
require a shut-in time to function, the well
should be returned to production as soon as
possible.
• Contains penetrating agent to help acid
contact damage.
• Contains clay stabilizer to control fines
migration during and following the
treatment.
Volcanic Acid
Volcanic Acid is a new organic-HF acidizing
blend developed to replace acetic-HF and
formic-HF fluids. This system is unique to
Halliburton. Recent research (including
laboratory reactions, core flow tests, and
flowback sample analyses from organic-HF
treatments) has shown that the acetic-HF and
formic-HF systems have severe secondary
precipitation of HF reaction products. The
systems are effective in removing skin damage
and increasing production in wells in which
HCL-based fluids could not be used. However,
secondary reactions further from the wellbore
K-Spar Acid
K-Spar Acid is a 9% HCL-1% HF blend which
was designed for treating formations containing
significant sodium or potassium feldspar or
illite. As the sodium and potassium are
dissolved from these minerals, the potential for
fluosilicate precipitation increases. Potassium
fluosilicate is less soluble and presents a bigger
problem. K-spar Acid should be used in almost
all cases where the formation contains K-spar
and/or illite as the dominant mineral, or the
© 2005, Halliburton
• Contains Fe-1A for iron control and
preventing aluminum scaling.
8 • 30
Stimulation I
Chemical Stimulation
precipitate the HF reaction products giving a less
than optimum overall treatment. Volcanic Acid
solves these problems while maintaining all the
advantages of organic-HF fluids.
The primary advantages of Volcanic Acid are:
• Is compatible with HCL-sensitive minerals
• Can be used at higher temperatures than
HCL-based fluids, without decomposing
clays or zeolites or having high corrosion
rates.
and asphaltenes or scale removal treatments
may also be required.
3. Pump 100 to 200 gal/ft of Gidley's CO2
Conditioner (optional). Applicable for oil
wells with emulsion problems, terminal
upset problems, or to enhance contact of
acid into the oil zones.
4. Pump 50 to 150 gal/ft of non-acid CLAYFIX
5 Conditioner (optional). CLAYFIX 5
Conditioner is recommended in formations
with a high ion-exchange capacity. It also
should be used when completion brines or
kill fluids have not been recovered from the
well and need to be displaced from the nearwellbore area to avoid contact with acid
fluids. If the crude oil or formation brine
shows incompatibility with the acid fluids,
the non-acid preflush may also be necessary.
• Typically will not cause sludging with
formation crude oils, even with those prone
to acid sludging.
• Avoids secondary precipitation observed
with formic-HF and acetic-HF.
• Contains NH4Cl to prevent swelling of
water-sensitive clays.
5. Pump 50 to 150 gal/ft of appropriate acid
conditioner. Acid fluids are required prior to
the HF-containing damage removal fluid
systems in order to ion exchange and
remove carbonates. HCL, CLAY-SAFE 5,
or CLAY-SAFE H should be used. The
choice of these fluids depends upon damage
mechanism, mineralogy, and temperature.
• Contains a penetrating agent to help acid
contact damage.
• Can be used anywhere formic-HF or aceticHF fluids were previously used.
The name Volcanic Acid came from the fact that
formations with high zeolite content and high
clay content are often associated with areas of
volcanic activity. The name also has the
connotation of high temperature. The Volcanic
Acid fluid systems are specifically suited for
these types of formations.
6. Pump 75 to 200 gal/ft of appropriate
damage removal fluid system. When using
Fines Control Acid, pumping a small
nonretarded HF stage is often beneficial in
removing very near-wellbore damage.
7. Overflush with 25 to 200 gal/ft of 5-15%
HCL or CLAYFIX 5. Overflush is required
to push the treatment fluids deeper into the
formation. The larger volumes are required
with brines incompatible with spent acid or
for disposal wells where the fluids are not
recovered.
General Treatment Guidelines
Designing sandstone acidizing treatment may
seem very complicated due to the numerous
considerations that must be dealt with, but
following the 8 general steps listed below and
the decision tree in Figure 8.7, the goal of
improving well performance can keep things in
perspective.
8. Displace with clean fluid such as nitrogen
or CLAYFIX 5. Volumes should be
sufficient to fully displace any acid fluid
away from the wellbore and the gravel pack.
Never use KCL, or formation brine to
displace since these fluids will be
incompatible with spent acid.
1. Perform mud cleanout treatment if whole
drilling mud was lost. Additional fluid
should be circulated until returned fluid is
clean.
2. Perform wellbore cleanout treatment. This
should include pickling the tubing with HCL
at the least. Solvent treatments for paraffins
© 2005, Halliburton
8 • 31
Stimulation I
HF Acid Flow Diagram
W ellbore A rea D amaged?
Don’t use HF
Yes
No
Is dama ge H F a cid soluble?
Don’t use HF
No
Yes
Damag e remov ed, will production be e conomica l?
D on’t use H F
Yes
No
Pump at re asonable ma trix inje ction rate?
Don’t use HF
Yes
No
Carbo nate Conce ntra tion > 20%?
Don’t use HF
Yes
No
C an treatment be control le d to tre at all in terval of Interes t?
U se HF
Yes
No
Nec ess ary to tre at t he whole i nt erval t o ma ke well ec onomical?
D on’ t use H F
U se HF
Yes
No
Figure 8.7 – HF acidizing decision tree
© 2005, Halliburton
8 • 32
Stimulation I
Unit F Quiz
Fill in the blanks or mark the correct answer to check your progress in Unit F.
1. Hydrochloric acid used in sandstone acidizing is basically used to (check all that apply):
_____ a)
partially dehydrate water-swollen clay
_____ b)
dissolve clays
_____ c)
dissolve carbonates that are present
_____d)
create a fracture
2. Hydrofluoric acid will dissolve
_____a)
silica
_____b)
clays
_____c)
silt
_____d)
shales
_____e)
all of the above
3. The speed of hydrofluoric acid’s reaction on sandstone is affected by:
_______________________________________________________
_______________________________________________________
_______________________________________________________
_______________________________________________________
4. Halliburton’s name for ammonium chloride is ____________________.
5. Gidley’s CO2 process displaces ____________________ away from the wellbore to allow better HF
____________________ of the matrix and prevent ____________________ from forming.
6. Which Sandstone acid system would you choose for removal of deep damage (up to 2 to 6 in. from
the wellbore) caused by clay migration or swelling?
_____a)
Sandstone Completion Acid
_____b)
Fines Removal Acid
_____c)
Silica Scale Acid
_____d)
Volcanic Acid
Now, look up the suggested answers in the Answer Key at the end of this section.
© 2005, Halliburton
8 • 33
Stimulation I
Chemical Stimulation
Unit G: Damage Removal – Mud
considered before a mud removal operation is
started.
Since many mud systems are used for well
completion, it is almost impossible to describe
all of them, their properties, and how they might
affect production. Therefore, this unit is limited
to:
Limestone Formations
(1.) water base muds which contain clay
minerals
If damage from mud or mud filtrates exists in a
limestone formation, the exact nature of the
damage should be determined. If the producing
formation has not experienced excessive lost
circulation problems during the drilling
operation, then the problem is probably one of
the following:
(2.) oil base muds. Oil muds are either straight
oils or oil external emulsions.
It is desirable to remove muds from wells for a
number of reasons.
• very shallow clay particle invasion
Mud Removal
• possible filtrate invasion resulting in water
blocks
Water base mud, if properly combined, will
build a filtercake on the wall of the wellbore as
the well is drilled. The consistency of this
filtercake will vary from a tight, dense material
to a soft, mushy cake that allows excessive fluid
to penetrate into the formation. The mud’s fluid
loss properties must be constantly monitored to
do its job.
• possible changes in the formation
(particularly if naturally occurring water
sensitive clays are present)
Acid–Surfactant Mud Removal
Solutions (MCA-III)
As the well is drilled, the wiping action of the
bit, pipe, and tool joints on the on the sides of
the wellbore can remove the filtercake. This
allows more filtrate and even clay particles to
invade the formation. Also, excessive speed in
running the pipe can cause fracturing and loss of
whole mud to the formation. Many factors can
contribute to lost circulation problems, including
natural fractures and the vugular porosity of
some formations.
If the formation is limestone, any acid solution
that penetrates the mud or filtercake should
result in increased production. To penetrate a
mud filtercake, a surfactant is often added to
hydrochloric acid. The surfactant Morflo III
also acts to cure other problems associated with
mud damage. In addition to aiding penetration
of the filtercake, Morflo III can
• aid in thinning whole mud
Damage results when filtrate, clay, and whole
mud invade a formation. This damage can
seriously restrict the well’s production capacity
or injectivity if it is an injection or disposal well.
The degree of damage can be determined
through pressure buildup tests. If damage does
exist, steps can be taken to remove the damaged
condition. Potential damage and the
composition of the formation should be
© 2005, Halliburton
• lower surface and interfacial tension to
prevent or remove water blocks
• aid emulsion breaking or prevention of
emulsions
• assists in dispersing the clay minerals and
other insoluble fines after acid has done the
job of shrinking the clay
8 • 34
Stimulation I
Chemical Stimulation
One potential problem with whole mud removal
is that even when acid is used to shrink clay
particles in the mud system, it does not
necessarily mean the mud will be thinned. In
fact, the opposite can occur because the acid
may flocculate or cause the clay particles in the
mud to clump together.
Sandstone Formations
Removal of water base muds from a sandstone
reservoir should follow much the same pattern
as that of a limestone formation with some slight
changes. Where the calcium carbonate content
of the formation is low, hydrofluoric acid can be
used.
To minimize this flocculation and mud
thickening, Morflo III is added to the acid, and
the acid strength is maintained at the lowest
possible level. Usually 5 to 10% acid is used for
this work. Less than ½ % of the acid in the
solution is required for dehydrating the clay.
The rest can be used for dissolving lime in the
mud and limestone from the formation. If the
acid concentration used is 15% or higher, even
the special surfactant may not be capable of
thinning the mud effectively. Therefore, low
concentrations of acid solutions are
recommended.
Hydrofluoric-Hydrochloric Acid
Mixtures (HF Acid)
One precaution that should be pointed out is that
the fluoride ion (F-) will react with calcium ions
(Ca++) to form a damaging precipitate. Serious
damage could result if it forms in excessive
amounts in the intergranular porosity of a
sandstone formation. Limestone content of
sandstone formation is generally low enough so
that this problem will not occur. If limestone
content is too high where you can’t put enough
HCL ahead to get rid of it, then HF should not
be used. If the well has had a weighted clear
completion fluid (such as 40% calcium chloride)
used in it, damage could result. A spearhead of
dilute hydrochloric acid is almost always
recommended ahead of HF.
Non-Acid Mud Removal
Solutions (Mud-Flush)
Mud-Flush lowers the viscosity of water-based
mud systems and helps keep the solids in a
dispersed state. Mud-Flush has several
applications comparable to MCA-III, but it
cannot remove hard, dehydrated, filtercake from
a formation. Although Mud-Flush is not
considered a replacement for MCA-III, it is a
more economical alternative for use in lostcirculation situations. For example, if 100 bbl of
water-based mud was lost to a producing
formation, the volume of MCA-III required to
contact and chemically react with the mud
would be expensively large.
If whole mud or a mud filtercake is present on
the formation face or in perforation, it can be
removed by MCA-III. An appropriate surfactant
can also be added to HF-HCL mixtures for the
mud removal. The comments on concentrated
acid are still true. Even with HF solutions,
flocculation can result, and whole mud
thickening may be observed. Filtercake and
mud invasion, as well as clay within the
formation, may be removed by HF Acid.
Mud-Flush is a mixture of a mud thinner (MF-1)
and MORFLO® III. The action of these two
chemicals dissolved in water is sufficient to
perform the following functions:
The Mud-Flush solution previously mentioned
can be used for whole mud removal in sandstone
formations in the same manner as discussed for
limestone formations.
• Aid removal of water-based drilling muds
from all types of formations
Oil Base Muds
• Help prevent and break emulsions and water
blocks
Two basic oil mud systems require attention: the
Oil External Emulsion Muds and the True Oil
Base Muds.
Mud-Flush should not be used for removing oilbased mud.
© 2005, Halliburton
8 • 35
Stimulation I
Chemical Stimulation
N-Ver-Sperse O consists of
Oil External Emulsions (Invert
Emulsions)
• hydrocarbon solvents, such as diesel oil,
kerosene, or xylene
Emulsions used for drilling are usually fairly
low solid, oil external, oil wet clay stabilized
emulsions. They can be broken, with
undesirable results, if too much of a high surface
area solid such as clay is added to the system.
They can also be broken with appropriate
emulsion breakers in some instances.
• 5% MUSOL® or MUSOL A solvent
• and HYFLO® IVM surfactant
If the muds contain asphaltic materials, use
xylene for the hydrocarbon solvent.
Use N-Ver-Sperse A fluid, containing wetting
agents and dispersants, when hydrocarbon-based
fluids must be avoided because of economics,
environmental concerns or lower hydrostatic
pressures. The aqueous system also can be used
as either a mud cleanout fluid or a formation
breakdown fluid. When used as a mud cleanout
fluid, gelling agents can be added to give the
fluid sufficient viscosity to carry the mud solids
from the wellbore. It can also be weighted to 11
lb/gal using zinc chloride. Materials, such as
calcium chloride and sodium bromide, are not
satisfactory weighting salts. Sodium bromide
can be used for weighting, however, if methanol
is included in the formulation. Test weighted
solutions at specific well conditions before use.
True Oil Base Muds
True oil base muds are usually prepared by
gelling a viscous, high asphaltene oil and adding
to it blown asphalt, fine calcium carbonate, and
other materials which can have fluid loss
properties. One of the most effective thinning
and removal solutions consists of glacial acetic
acid or acetic anhydride mixed with an aromatic
solvent containing Hyflo IV. These will also
water wet the pipe and formation.
Some oil base type muds tend to spontaneously
form a very viscous emulsion with certain
cements. This emphasizes the need for a wash
ahead of the cement.
N-Ver-Sperse A consists of
• water containing 2% KCl by weight
• 10% MUSOL
N-VER-Sperse
(NOTE: MUSOL A is not recommended
because of separation problems noted at
higher temperatures)
N-Ver-Sperse A and N-Ver-Sperse O have been
developed to help clean up a well where oil
based muds have been used.
• 1% MORFLO III by volume
Use N-Ver-Sperse O fluid when the presence of
a hydrocarbon fluid would be advantageous. Use
it either as a cleanout fluid to remove mud from
the wellbore and formation or as a formation
breakdown fluid. When used as a mud cleanout
fluid, circulate N-Ver-Sperse O at a fairly high
rate to prevent the solids in the mud from
settling out.
© 2005, Halliburton
8 • 36
• 50 lb SPACER SPERSE per 1,000 gal of
fluid.
Additional References
Acidizing Methods and Materials (Mud
Removal) - HalWorld
Stimulation I
Chemical Stimulation
Unit G Quiz: Damage Removal-Mud
Fill in the blanks or mark the correct answer to check your progress in Unit G.
1. Damage can result when ____________________, ____________________ and
____________________ ____________________ invade a formation.
2. Two solutions that can be used to remove mud damage in a limestone formation are
____________________ and _____________________ ____________________.
3. ______ True
______ False
Mud damage in a sandstone formation can be removed with HF Acid
if the limestone content is high.
4. The two types of oil base muds are ________________ ____________________ ________________
and ________________ ________________ ________________ muds.
5. ____________________ and ____________________ are two solutions for removing oil base muds.
Now, look up the suggested answers in the Answer Key.
© 2005, Halliburton
8 • 37
Stimulation I
Chemical Stimulation
Unit H: Paraffins and Asphaltenes
the deposition problem varies between reservoirs
in the same area and between wells in the same
reservoir. The severity is difficult to estimate
until it cannot be controlled by normal
production techniques. Many operators have
learned to live with their situation and have
“grown-up” with their removal techniques.
Therefore, they tend to treat the problem as an
unavoidable part of life.
Other than the physical properties and condition
of the producing formations, one of the most
aggravating problems for the petroleum
producer is the build-up of organic deposits in
areas like the well bore and feed lines. These
deposits act as chokes during build-up in the
well bore. They gradually decrease production
and, in time, could completely stop the flow of
oil. This may cause rod failure, split tubing, and
worn pump parts unless some remedial action is
taken. Two common actions are
•
an orderly program for the removal of the
deposits
•
the use of some type of inhibitor.
Cloud Point and Pour Point
Cloud point and pour point tests are used to get
general measurements of the ability of the crude
oil to hold paraffin in solution. These are
experimental measurements that give us some
idea where or when paraffin might cause
problems.
The petroleum industry spends millions of
dollars annually correcting these deposition
problems.
Organic deposits are formed when the chemical
equilibrium of the oil is upset. This causes
certain chemicals normally in solution to
precipitate. The physical and chemical
characteristics of many crude oils are such that
the oils can deposit waxy material called
paraffins or, in some instances, asphaltenes.
The cloud point is defined as the temperature
where paraffin begins to come out of solution.
This point is visible in clear crude oils as a slight
cloudiness. Obviously the cloud point of a dark
crude oil has no meaning since the cloudiness is
not visible. Other instrumental methods are
sometimes used to obtain the cloud point of
crude oils.
Paraffins
If the liquid or crude oil is slowly cooled below
the cloud point without agitation, small wax
crystals gradually form an interlocking network
that will support the liquid. A temperature is
finally reached where the oil will not flow when
tilted to a horizontal position in a bottle. This is
referred to as the pour point. This point has
more meaning when dealing with crude oils.
Generally, the higher the cloud point or pour
point of an oil, the less stable the paraffin is in
the oil.
The family of hydrocarbons classified as
paraffins is generally inert. They are resistant to
dissolving in acids, bases, and oxidizing agents.
This makes it difficult to remove these deposits
chemically.
Depending on the conditions where paraffin
deposits were formed, they have different
physical forms. These forms include soft mush
to hard, brittle deposits. Also, paraffin deposits
will often include other materials such as scale,
sand particles, or asphaltenes.
Paraffin problems are encountered in almost
every oil producing area. Some areas are more
severely affected than others. The severity of
© 2005, Halliburton
8 • 38
Stimulation I
Chemical Stimulation
Factors Affecting Paraffin
Deposition
expand and cool. The largest amount of cooling
is usually at the formation face.
Paraffin deposition is primarily due to a
reduction in the amount of paraffin that can be
dissolved in a crude oil. This loss of solubility
can be caused by many different factors. Some
of the more important factors are discussed
below.
Loss of Volatile Constituents
from the Crude
Generally, the light parts of a crude oil are the
ones that dissolve the most paraffin. Loss of
these lighter constituents reduces the quantity of
paraffin that the oil can hold in solution at a
specific temperature.
Temperature
In most solutions, as you lower the temperature
the material dissolved in the fluid begins to drop
out of solution. This is also true of paraffins.
As oil is produced, its temperature can drop for a
variety of reasons. Cooling can be produced:
• by gas expanding through an orifice or
restriction (choke)
As a producing field becomes older, the lighter
constituents are constantly being removed from
the oil, even within the formation. Therefore,
the oil becomes more saturated with paraffin
before it ever leaves the formation. For this
reason, many paraffin deposition problems
become more severe as the well becomes older.
• as a result of the gas expanding, forcing the
oil through the formation to the well and
lifting it to the surface
• by loss of heat from the oil and gas to the
surrounding formations as it flows from the
bottom of the well to the surface
Suspended Particles in the
Crude
• by dissolved gas being liberated from
solution
• by water production
As was stated previously, paraffin begins to
separate from crude oil when the temperature of
the oil cools and the paraffin is no longer stable
in solution. There is some evidence that
formation fines such as sand and silt often speed
this separation process. These small particles
suspended in the crude act as a nucleus for the
small wax particles to form into larger particles.
These separate more readily from the oil.
Paraffin problems are greatly increased when
these fines are present, especially since fines
tend to increase the bulk of the deposit.
• by the evaporation or vaporization of the
lighter constituents
• in oil flow lines due to loss of heat to air
(especially in winter)
Pressure
Pressure helps keep gas and lighter constituents
dissolved in the crude oil. If the wellhead
pressure were the same as formation pressure,
paraffin would probably not cause many
problems.
Conditions Favoring Paraffin
Deposition
However, oil will not flow unless there is some
type of pressure drop. The largest percentage of
this pressure drop occurs near the bottom of the
well. As the pressure decreases, oil and gas
© 2005, Halliburton
Evaporation of the volatile constituents in crude
oil also tends to reduce the temperature of the
oil. This is due to the heat required to change
the liquid to a vapor. This effect is not as
important as the loss in solubility mentioned
above.
Even though wax may separate from the crude
oil, the paraffin will not necessarily deposit on
8 • 39
Stimulation I
Chemical Stimulation
the tubular goods and other objects. The wax
will probably remain suspended in the crude oil
itself. This ideal situation often exists. In some
wells producing very waxy crude, little or no
paraffin problems are experienced.
On the other hand, some crude oil areas with
“low” paraffin content have some severe
problems. Listed below are some conditions
that are favorable for paraffin deposition:
• The alternate coating of the pipe and
draining of the oil. As the pipe fills, then
drains, the film left on the pipe surface is too
thin and its movement too slow to carry the
wax particles away.
• The presence of only a film of oil in contact
with the pipe while the well is flowing.
One obvious method of minimizing this problem
would be to heat the stimulation fluids on the
surface. Another method might be to run a
paraffin solvent ahead of the job.
Methods Used to Remove
Deposits
• When the oil contacts with an unusually
cold surface such as the production of oil
through water zones. This will cause
paraffin crystals to grow directly on the pipe
wall. It is estimated that the heat loss from a
pipe in contact with water is approximately
eight times greater than when in contact
with air or dry earth.
Methods generally used to remove
accumulations of paraffin can be classified as
follows:
• Those that remove the paraffin by use of
mechanical equipment.
• Those that remove the paraffin by use of
solvents which dissolve the deposits.
• Rough pipe surfaces.
• Electrical charges on various materials in the
crude oil.
These conditions favoring paraffin deposition
combined with a sufficient cooling of crude oil
can cause serious problems.
• Those that use heat, which melts the wax and
reduces it to a liquid so that it can easily be
removed with produced oil.
Mechanical methods such as scrapers, knives,
hooks, and other tools for the removal of
paraffin deposits offer fairly satisfactory results
when the wax accumulation is in the well bore.
Tools such as these are common in the oil field
and will not be discussed here.
Paraffin Precipitation during
Fracture Stimulation
Studies have been conducted on the effect of
injecting cold fluids into a warm, producing
reservoir. It was found that the crude oil can
deposit paraffin in the formation when the
reservoir is cooled by large volumes of cold
fluids such as those used in fracturing
treatments. This is particularly true when the
surface fluid temperature is cooler than the
formation temperature. If the fluid in the
formation is cooled to a temperature below the
cloud point, paraffin precipitates may deposit in
the formation pores. Once this occurs, the fluid
© 2005, Halliburton
flow channels become partially blocked or
plugged, and the flow of oil is restricted. Even
after the original formation temperature is
restored, it may be difficult to redissolve the
precipitated paraffin in the same fluid. This is
because the melting point of solid paraffins is
much higher than the cloud point. However,
formations having temperatures higher than the
melting point of the precipitated paraffin would
not be affected.
Hot Oil
One of the most common techniques of
removing paraffin deposits is to dissolve or melt
waxy accumulation with hot oil. This removal
method is very simple. Lease crude is run
through heat exchangers and pumped into the
well at temperatures in excess of 300°F. This
will usually melt the accumulated paraffin in the
oil string. The paraffin is then produced back
with the oil. Many small businesses own and
8 • 40
Stimulation I
Chemical Stimulation
operate specially designed hot-oil trucks. Many
wells are hot oiled at regular intervals ranging
from every two to four weeks or more.
Parasperse Additives
There is some evidence that hot oiling may be
detrimental to crude oil production. Paraffin
damage is caused when temperatures higher than
the formation temperature is used to melt the
paraffin wax. As the hot oil is circulated, some
of the liquid containing a high concentration of
paraffin may leak off into the producing zone
where it cools to the formation temperature.
This allows paraffin to reprecipitate within the
formation. When this type of damage is
suspected, it often requires several soakings with
a good paraffin solvent to clean the wax out of
the formation matrix.
Many crude paraffin deposits contain inorganic
solids such as corrosion products, scale, and
formation fines. These solids can comprise as
much as 60% of the paraffin deposit. If the
paraffin is melted by the hot oil, the solids could
be forced into the formation matrix and create
another source of damage.
Steam
Steam has been used successfully in a number of
fields having severe paraffin problems. The
application of steam heat to the formation is a
practical method of heating the sand and
removing paraffin from the formation face. One
disadvantage of this method could be the
possibility of plugging the producing zone with
paraffin in much the same manner as with hot oil
jobs.
Aqueous Paraffin Removal Systems
Parasperse has proven very successful in both
laboratory and field tests as a water-dispersible
paraffin removal agent.
One of the most successful applications of
Parasperse® cleaner is periodic cleaning of the
formation face. Other applications include
wellbore cleanout, flowline cleaning, paraffin
inhibitor placement, and as a preflush in
fracturing. This material can be used as an
alternative to hot-oiling downhole. Parasperse®
is ordinarily used at a concentration of 2-10% in
a water carrier. This water may be produced
formation brine or clean surface water.
Successful treatments have been noted when
cold water was used. Preferably, the system
should be warmed to about 100-120°F to aid the
cleaning action of the Parasperse® solution. In
laboratory tests, the Parasperse® solution
removed more crude paraffin than is dissolved in
conventional paraffin solvents.
Parasperse® treatments are also less expensive
than conventional paraffin solvents. Since water
comprises 90-98% of the removal system, the
chemical expense is very reasonable. In many
instances, Parasperse® treatments have
significantly increased the production of a well.
Paraspserse T was designed for the removal of
both paraffins and asphaltenes. It has the same
applications as Parasperse.
Parasperse LR was primarily designed for use in
hydrocarbon-based fluids. However, it can also
be added to aqueous fluids and has the same
general applications as the other Parasperse
additives.
Solvents
Certain water-based chemicals have been
successfully used to remove downhole paraffin
deposits. These chemicals, when added to
water, have the ability to remove accumulated
organic deposits and disperse them for easy
removal.
The use of solvents to remove paraffin deposits
is becoming more common in the oil field.
Many laboratory studies have been conducted on
a variety of solvents in an attempt to determine
the best solvents for paraffin and how the
solubility varies with different waxes.
In general, the solubility of different waxes in a
given solvent at a definite temperature decreases
© 2005, Halliburton
8 • 41
Stimulation I
Chemical Stimulation
as the molecular weight and melting point
increase.
loss, produce the oil out of the well bore rapidly,
and minimize agitation of oil in the wellbore.
The usual practice has been to dissolve paraffin
accumulations using light, hydrocarbon solvents
such as kerosene, naphtha, gasoline, diesel fuel,
etc. These solvents are very effective for
dissolving purified paraffins such as canning
waxes. However, crude waxes are usually
deposited with a considerable quantity of
asphaltenes present. Because asphaltenes are
insoluble in most solvents, they tend to hinder
the dissolving of the waxes present in the
deposit. This makes the solvent less effective in
dissolving the total deposit.
Electrical Heaters
The use of bottom hole heaters is a less
satisfactory means of controlling paraffin
deposition. Heaters are designed to heat the oil
as it comes out of the formation in order to keep
the paraffin “in solution.” The use of this
technique is severely limited by economics, high
maintenance costs, and the absence of electricity
in isolated fields.
Plastic Coatings
PARAGON Solvents
Tests show that aromatic solvents such as xylene
and toluene dissolve both the wax and the
asphaltenes. These two solvents are excellent
for treating crude paraffin deposits.
Halliburton’s Paragon is an effective blend of
aromatic solvents.
Paragon 1 and Paragon 100E+ effectively
dissolve paraffin without using benzene, ethyl
benzene, toluene, or xylene (BETX). The use of
one or more of these four materials may be
restricted in certain areas due to government
regulation.
Paragon EA™ is a cost-effective solvent for the
removal of excess pipe dope, paraffin deposits,
and crude oil residues. In most cases, Paragon
EA will be applied as a neat solvent. Unlike
Xylene and Paragon 100E+, Paragon EA does
not contain any aromatic components and is
environmentally acceptable.
Plastic pipe used as feedlines and plastic coated
pipe used in the well has received much
attention in the last few years as a means of
combating paraffin deposition. Extruded plastic
pipes and plastic coatings have proven effective
in some areas.
The idea behind the use of plastic coatings on
downhole equipment is that paraffin will not
adhere to the smooth surface provided by the
plastic. In some cases this is true; however,
most plastic coatings will not withstand the
rough treatment given to downhole equipment.
Therefore, the coating becomes scratched and
worn and provides an excellent base for paraffin
deposition. In some instances, certain types of
plastic coatings actually promote the deposition
of paraffin. This method of combating paraffin
deposition is also very expensive, especially if
the existing iron has to be junked and new
plastic coated equipment placed in the well.
Surfactants
Methods for Decreasing the
Severity of Deposition
Many of the chemicals used to combat paraffin
problems are just ordinary surfactants or
dispersants. The surfactants work by waterwetting the tubular goods. This water film helps
keep paraffin from sticking to the pipe wall.
Dispersants work by reacting with paraffin and
causing the particles to repel each other.
Altering Production Techniques
Altering production techniques is one way to
avoid paraffin problems. There are many
methods that can be used to cut down on heat
© 2005, Halliburton
8 • 42
Stimulation I
Chemical Stimulation
These approaches have been partially successful.
However, there is no information on when they
will work. It is mostly a trial-and-error method.
The squeeze treatment is done by diluting 1
drum of paraffin inhibitor per each 50 bbl. of
produced crude per day in 500 gallons of
diesel, kerosene, xylene, Paragon, or lease
crude. Thus, for a 50 BOPD (barrels of oil per
day) well 1 drum of inhibitor diluted to 500
gallons would be required; for a 100 BOPD
well 2 drums of inhibitor diluted to 1000
gallons would be required, etc. Once the
inhibitor is spotted downhole, it is then overdisplaced with 5-10 bbl. of lease crude per foot
of formation. Inhibitor treatments as outlined
above should theoretically give about 200 days
protection against paraffin deposition.
Crystal Modifiers
Generally, crystal modifiers have many of the
same drawbacks of surfactants. They appear to
be somewhat unpredictable in their
effectiveness. However, with the proper
placement technique, they seem to work fairly
well and offer the most hope for the chemical
inhibition of paraffin deposition. When viewed
under a microscope, they appear to modify the
wax crystals precipitating from a solution. The
normal crystal growth of paraffin is deformed
sufficiently to inhibit further growth. The crude
oil becomes filled with paraffin crystals that are
much smaller than normal and have fewer
tendencies to adhere to pipe surfaces. While not
completely curing the paraffin problem, crystal
modifiers help reduce the severity of the
problem.
Parachek® 160 paraffin inhibitor continuous
injection into the crude stream may be
accomplished by metering the inhibitor
downhole with a small surface chemical pump,
by injection into the power oil on wells
equipped with a subsurface hydraulic system,
or by using a bypass feeder arrangement. One
advantage to the continuous injection of the
paraffin inhibitor is that conscientious
operating personnel can carefully control the
concentration of the chemical. In all continuous
injection applications, the inhibitor must enter
the crude stream well ahead of the point of
paraffin deposition. This is imperative for a
successful treatment.
Parachek® 160 Inhibitor
Parachek® 160 inhibitor is an effective blend of
chemicals that may be classed as crystal
modifiers. Parachek® 160 has been found to be
effective in relieving paraffin problems
encountered in most crude oil producing areas.
However, it should be noted that Parachek® 160
does not prevent the paraffin crystals from
coming out of solution in the crude oil. Once the
crude oil becomes saturated with dissolved
paraffin, paraffin crystals begin to form in
solution. Parachek® 160 is not a paraffin solvent
and should not be used in place of Paragon or
Parasperse. That is, it is not to be used as a
paraffin removal solution, but rather as
prevention against paraffin deposition.
It is possible that Parachek® 160 could be
placed during other remedial treatments on a
well, such as a propped fracturing treatment.
Paracheck® 160 is not ordinarily dispersible in
aqueous solutions; however, it could be
injected into an aqueous fracturing fluid
providing the pump rate is sufficient to keep it
dispersed. Parachek® 160 can also be added by
mixing with Parasperse. Parachek 160 has not
been tested to determine if it has a detrimental
effect on the gel properties of My-T-Oil IV and
My-T-Oil V, so compatibility testing would
need to be conducted before attempting to use it
with these fracturing fluids.
There are three different applications that may
be used to introduce Parachek® 160 into the
crude oil stream. These are:
•
squeezing into the formation
•
continuous application
•
introduction into other stimulation
fluids.
© 2005, Halliburton
In all applications a concentration of 0.5 to 0.75
gallons of inhibitor per 100 bbl. of produced
crude oil should be maintained.
8 • 43
Stimulation I
Chemical Stimulation
tends to aggregate (form) the asphaltene
particles. The breaking of this bonding allows
better solvent penetration and increases the
dissolution rate of the asphaltenes.
Asphaltenes
Asphaltenes are generally considered to be
suspended particles in the oil. Unlike paraffins,
they are not soluble in the light constituents of
oil. Asphaltene deposition can be caused by
some of the same conditions as paraffin.
However, it is believed that asphaltene deposits
are caused by the inability of a crude oil to keep
the particles dispersed.
Targon® II is used from 1 - 10% by volume of
the carrier. It will not work in solvents such as
kerosene, diesel, gasoline, condensate, etc.
Tarchek
Asphaltene precipitation is less widespread in
the United States than is paraffin precipitation.
It appears that certain fields in Mississippi and
California are the most susceptible to this type
of deposition. However, any well producing
asphaltic base crude may experience this
problem. Asphaltene deposition is also a
problem in many areas outside the United States.
Where asphaltene precipitation is a problem, the
deposition usually occurs at the bottom of the
well bore and adjacent to the producing
formation. In some instances the asphaltenes
may precipitate within the formation itself and
cause damage.
Targon® II Solvent
Targon® II is an organic solvent used to remove
asphaltene deposits. This solvent was designed
for use with an aromatic solvent carrier
(Paragon). Targon® II was designed to use as an
additive in aromatic solvents to enhance their
asphaltene dissolution properties by breaking
down the strong intermolecular bonding that
© 2005, Halliburton
Tarchek is an asphaltene inhibitor for use in
wells with asphaltene precipitation problems. It
can be run in combination with such paraffin
inhibitors as Parachek®160 to treat crude oils
that have both paraffin and asphaltene problems.
Laboratory testing has shown that Tarchek does
not affect paraffin inhibition. Remember that,
like Parachek®160, Tarchek inhibitor is not a
solvent and should not be used in place of
Paragon solvent. The primary function of
Tarchek inhibitor is not to remove asphaltene
deposits, but to prevent asphaltene from
depositing. Before applying Tarchek, clean out
any existing asphaltene deposit either
mechanically or by using a solvent soak
consisting of Paragon and the appropriate
amounts of Hyflo®IV M surfactant and
Targon®II solvent.
Tarchek asphaltene inhibitor stabilizes the
asphaltenes by preventing their flocculation
(clumping) and/or deposition; thereby,
protecting the entire production system from
asphaltene plugging.
8 • 44
Stimulation I
Chemical Stimulation
Unit H Quiz
Fill in the blanks with one or more words or circle the correct answer to check your progress in
Unit H.
1. ______ True
______ False
Most organic deposits in a well contain both paraffin and asphaltene.
2. ______ True
______ False
Paraffin problems are rare in the oilfield.
3. The cloud point is the ____________________ when paraffins begin to come out of
____________________.
4. The pour point is the ____________________ when oil can no longer ____________________.
5. Factors affecting paraffin deposition are:
__________________________________________________________________
__________________________________________________________________
__________________________________________________________________
__________________________________________________________________
__________________________________________________________________
6. ______ True
______ False
It is impossible to cause paraffin deposition during a stimulation job.
7. Paraffin removal is accomplished by:
__________________________________________________________________
__________________________________________________________________
__________________________________________________________________
8. Parachek® 160 inhibitor is an effective blend of chemicals that may be classed as
____________________ ____________________.
9. ____________________ can be used to help dissolve asphaltenes when added to Paragon and
____________________ can be used to prevent asphaltene precipitation.
Now, look up the suggested answers in the Answer Key at the end of this section.
© 2005, Halliburton
8 • 45
Stimulation I
Chemical Stimulation
Unit I: Scale Removal and Prevention
The deposition of scaling material from brines
produced with oil has been a serious problem for
many years. Compounds such as calcium
sulfate, calcium carbonate and barium sulfate
have been found in many wells. These deposits
may exist in injection wells, producing wells and
waste disposal wells.
Scale Effects
The effects that scales caused by brine
production have on a well depend largely on the
type of scale in the system. Scales may restrict
and completely choke off production in the
tubing, flow lines, or tubing perforations either
at the formation face or in the perforations.
Scales have been suspected of depositing in
fractures or in the formation some distance from
the well bore.
Chemical
Formula
Scale Type
Mineral Name
Water Soluble Deposits
Sodium
Chloride
NaCl
Halite (salt)
Acid Soluble Deposits
Calcium
Carbonate
CaCO3
Calcite
Iron Carbonate
FeCO3
Soderite
Iron Sulfide
FeS
Trolite
Iron Oxide
Fe3O4
Magnetite
Fe2O3
Hematite
Mg(OH)2
Brucite
Magnesium
Hydroxide
Acid Insoluble Deposits
Scale not only restricts production, but also
causes inefficiency and production equipment
failure. Since many older fields have entered
into enhanced recovery stages, scaling problems
can have an even greater impact on waterflood
operations.
One of the most important factors in dealing
with scaling problems is to have an accurate
identification of the material being deposited.
There are essentially two methods used in the
laboratory for the identification of scales. One
involves the use of an instrumental method (xray diffraction). The other uses chemical
methods.
Calcium Sulfate
CaSO4 2H2O
Gypsum
Calcium Sulfate
CaSO4
Anhydrite
Barium Sulfate
BaSO4
Barite
Strontium
Sulfate
SrSO4
Celestite
Barium
Strontium
Sulfate
BaSr(SO4)2
Table 8.5 - Oilwell Scale Deposits
Types of Scale
Scales can roughly be divided into three classes:
•
water soluble
•
acid soluble
•
acid insoluble
These are based on the ability of water or
hydrochloric acid to dissolve the scale. This is a
simplified division (see Table 8.5) because many
times pure calcium sulfate or pure calcium
carbonate is not deposited. The scale deposit is
© 2005, Halliburton
8 • 46
Stimulation I
Chemical Stimulation
usually a mixture of one or more of the major
scales plus corrosion products, solidified oil,
silicates, paraffin, etc. However, separation into
water soluble, acid soluble or acid insoluble is
adequate for field analysis.
Scale Formation
Prior to production, well fluids remain in a
static, undisturbed state. Scale deposits occur as
a result of disturbing this equilibrium. When
production is started, a pressure drop occurs near
the well bore. This pressure change allows
dissolved gases to come out of solution. Since
changes destroy the state of equilibrium,
deposits can form. For example, calcium
carbonate scale can occur as a result of a
pressure drop at the well bore. Calcium
carbonate does not exist in the formation brine
as calcium and carbonate ions, but as calcium
and bicarbonate ions. A change in pressure
allows carbon dioxide (CO2) to escape from
solution. Calcium carbonate scale can then be
formed.
Scale deposits may also occur as the result of
mixing incompatible waters. Waters from
different zones may become mixed in the well
bore, or injection water may mix with formation
water. In water injection wells, brines from
several sources may be combined and cause
compatibility problems which could form scale.
The incompatibility of mixed brines results
when one water contains a high concentration of
calcium or barium and the other water contains a
high concentration of sulfate or bicarbonate ions
in solution. As these waters mix, deposition can
occur because the final solution becomes
saturated with calcium sulfate, barium sulfate, or
calcium carbonate. These deposits may be
found on the rods, tubing or flow lines.
Scale Form
The Physical form of a scale deposit is
dependent upon the manner in which it was
deposited. Scale does not form spontaneously.
Instead, it occurs in stages. Scale molecules
form clusters over a period of time. As these
clusters grow, they become too heavy to remain
suspended in solution. They precipitate or
become deposits. The final crystal form of the
scale may resemble popcorn and be either soft
and fluffy or very hard and dense. The hard,
dense scales occur as the result of slow growth.
The soft, fluffy scales are often deposited
rapidly. Most inorganic scales appear in one of
three forms:
• thin scales or popcorn like
• laminated deposits
• crystalline deposits
Corrosion and microbial reaction products can
result in deposition of various iron scales such as
iron oxides and iron sulfide. Sulfate reducing
bacteria are a source of hydrogen sulfide which
can precipitate iron that is in solution, or the
hydrogen sulfide can react with steel. Iron in
solution can also be precipitated if oxygen is
introduced into a system. Iron oxide (rust) can
form on metal surfaces when oxygen is present.
© 2005, Halliburton
Figure 8.8 - Heavy Scale Deposits
8 • 47
The thin type scales are normally the most
permeable and easily removed. The laminated
or crystalline scale forms are less permeable and
harder to remove.
Factors such as pressure drops, temperature, and
the mixing of water can result in severe scale
problems. However, the formation of scale is
usually a situation with several possible causes.
As changes in the equilibrium occur, interaction
Stimulation I
Chemical Stimulation
of these changes with other conditions downhole
can result in deposits. The final form that a
particular scale deposit takes can significantly
affect efforts to remove the scale.
Figure 8.9 - Flowchart for field identification of scale
Acid Soluble Scale Removal
Regular Inhibited Acid
Acid soluble scales are:
Regular inhibited acid solution is normally 15 %
hydrochloric acid that contains corrosion
inhibitor. It is the basic acid for preparing
penetrating and non-emulsifying acid. It is not
normally used for scale removal.
• Calcium Carbonate
• Iron Carbonate
• Iron Sulfide
• Iron Oxides
Penetrating Acid
• Iron Hydroxide.
Penetrating acid solution is regular inhibited
acid that has 1 ½ gallons of Pen-5 or Pen-88 per
1000 gallons. Pen-5 and Pen-88 are surfactants
One or more of the following solutions can
remove these acid soluble scales.
© 2005, Halliburton
8 • 48
Stimulation I
Chemical Stimulation
that lower the surface tension of the acid
solution to approximately 25 dynes/cm.
Lowering the surface tension increases the
acid’s ability to contact the scale.
during the course of the acidizing treatment, iron
salts and oxides that were put into solution as
iron chlorides may form insoluble iron
hydroxides. These iron compounds can deposit
near the well bore and cause even lower
injectivity than before the treatment.
A penetrating acid solution can be successfully
used on scales containing only a small amount
of iron if it does not form an emulsion with the
formation fluids. When treating surface
pipelines, gathering lines, or other systems
where the solution will not enter the formation,
penetrating acid can be used for all acid soluble
scale. Under cold conditions, increasing the
concentration of the hydrochloric acid will
increase the reaction rate. With most iron
scales, it is usually best to use at least 20 percent
hydrochloric acid.
The pH control is based on the action of a weak
acid that reacts much more slowly on the
limestone scale and other acid soluble materials
than the hydrochloric acid reacts. While the pH
remains low (less than 3), the iron will not
precipitate.
Multiple Service Acid (MSA)
MSA contains a 10 percent concentration of
acetic acid. MSA’s greatest attribute in scale
removal treatment is that it will not damage
chrome-plated parts or alloy steels found in
downhole pumping. Calcium carbonate scales
are readily dissolved by MSA.
Non-Emulsifying Acid (NE)
Non-emulsifying acid solution is regular
inhibited acid that has one or more of the nonemulsifying chemicals added. Non-emulsifying
acid can also have Pen-5 or Pen-88 added to the
solution to help obtain the desired wetting
properties.
Paragon Acid Dispersion (PAD)
The non-emulsifying chemicals are added to
help prevent the formation of emulsions between
the treating solution and the formation fluids.
Non-emulsifying acid, like penetrating acid, is
used when the scale is primarily calcium
carbonate and the iron concentration is low.
Fe Acid
Fe acid contains hydrochloric acid along with a
blend of sequestering agents and a pH control
agent. During scale removal, the sequestering
agent contained in Fe Acid prevents the
precipitation of the iron by forming a complex
with the iron and keeping it in solution. Fe Acid
is most suited for the removal of iron
compounds from disposal and injection wells.
Paragon Acid Dispersion (PAD) is a mixture
that contains Paragon (an aromatic solvent),
acid, and a surfactant. The acid phase may be
prepared from a number of acid solutions and
selection of the acid phase depends on the
conditions involved. In scale removal
applications, the aromatic Paragon portion of the
dispersion is effective in removing paraffin,
congealed oil and other organic deposits. This
allows the acid to contact the scale and react
more completely. PAD has been injected as the
first stage for degreasing and removing acid
soluble material prior to a Gypsol or Liquid
Scale Disintegrator job for the removal of acid
insoluble gypsum.
These deposits normally occur near the well
bore and gradually block the permeability.
Hydrochloric acid will dissolve iron scales and
cause a temporary increase in injectivity.
However, as the acid spends on the formation
© 2005, Halliburton
8 • 49
Stimulation I
Chemical Stimulation
Gal 15% HCL/
cu ft of Scale
lb Scale/ gal
of 15% HCL
CaCO3 (Calcium
Carbonate)
95
1.84
Fe2O3 (Iron Oxide)
318
0.98
FeS (Iron Sulfide)
180
1.62
FeCO3 (Siderite)
111
2.13
Fe3O4
423
0.74
Type of Scale
Before placing the Gypsol, the wellbore should
be degreased with kerosene containing Hyflo IV
or with DopeBuster M. After pumping off the
kerosene, the acid reactive scales and corrosion
products should be removed with Fe Acid or
MSA. PAD made with Fe Acid or MSA can
also be used to degrease the well bore to remove
the acid reactive materials present. The acidcontaining solution should be completely
pumped off before placing the Gypsol. The
converted gypsum can then be removed by
dumping or pumping inhibited hydrochloric acid
or MSA. If the scale is extremely thick,
successive treatments may be necessary with
Gypsol followed by acid.
Table 8.6- Volume of scale dissolved in 15%
HCL
Acid Insoluble Scale Removal
Acid insoluble scales are:
Liquid Scale Disintegrator
• Calcium Sulfate
• Barium Sulfate
Liquid Scale Disintegrator or LSD, is an organic
solution that is designed specifically for the
removal of calcium sulfate scales, gypsum and
anhydrite. LSD reacts with gypsum to form a
precipitate that won’t adhere to gypsum but
forms a water dispersible sludge. The
precipitate has a tendency to slough away from
the surface of the gypsum and increases the
penetration of the solvent. Also, since the
precipitate does not adhere tightly and is readily
dispersible in water, an acid stage may not be
needed to remove the sludge. If it becomes
necessary to remove the LSD precipitate with
acid, it is soluble at 1.2 pounds per gallon of
15% hydrochloric acid.
• Strontium Sulfate
• Barium-Strontium Sulfate.
Two general types of conversion agents have
historically been used for scale removal; Gypsol
and hydroxide solutions. Since then, research
has developed a number of additional scale
removal chemicals that can be used.
GYPSOL
Gypsol gypsum converter is a water solution
containing one-half pound of OG-1 and one-half
pound of OG-2 per gallon of solution. A
surfactant, Pen-5, is also added at one gallon per
1000 gallons of the solution.
Laboratory and field tests have shown that most
gypsum deposits can be removed with LSD in
24 to 48 hours. Also, LSD is more effective
than Gypsol for removing gypsum scale. A
degreasing step with Paragon or a PAD solution
with Fe Acid as the acid phase is preferable prior
to the scale removal treatment. The degreasing
step should be circulated for 12 to 24 hours
before being pumped off. The LSD solution is
then dumped in the annulus. If the scale deposit
is present in fractures some distance from the
well bore, a soaking period prior to circulating is
recommended. If the scale deposit is considered
restricted to the well bore, circulation can be
started immediately after dumping. Since the
scale deposit may be oil wet, the addition of a
With Gypsol, gypsum (CaSO4∗2H20) is
converted to acid soluble calcium carbonate.
Gypsol is inexpensive and has been successfully
used in many wells. However, the converting
properties of Gypsol are severely retarded when
encountering dense, laminated gypsum scale.
Because of this lack of penetration, repeated
application may be necessary.
Gypsol works only with gypsum deposits.
Gypsol is normally placed in contact with the
scale for 24 to 48 hours and allowed to convert
gypsum to an acid soluble calcium carbonate.
© 2005, Halliburton
8 • 50
Stimulation I
Chemical Stimulation
suitable surfactant would allow better wetting
and contact.
7.0
6.0
NOTE: Emulsion tests should be conducted
with the LSD and non-emulsifiers added just as
they would be with an acid treatment. Wells on
gas lift or flowing wells must have the “spot and
soak” technique applied.
5.0
4.0
3.0
2.0
LSD can be used at concentrations ranging from
10-50%. Concentrations and volumes used are
determined by the amount of scale present
downhole. Figure 8.10 gives the theoretical
amount of gypsum removed by various
concentrations of LSD in pounds per gallon.
Note that these are theoretical values and
represent the maximum amount of gypsum that
can be removed. For instance, LSD-300 and
LSD-500 solutions will theoretically remove
4.35 and 7.0 pounds of gypsum per gallon,
respectively. However, laboratory tests
conducted with field scale samples have shown
that LSD-300 and LSD-500 solutions will
remove only 2-3 and 3-5 pounds of gypsum per
gallon in 24 to 48 hours under static test
conditions.
1.0
0
20
30
40
50
CONCENTRATION OF LSD (WT%)
Figure 8.10 - Theoretical Amount of
Gypsum Removed by Various
Concentrations of LSD (per gallon)
In cases as serious as the one mentioned,
circulating the LSD solution through the interval
would be more practical. The volume and
concentration of LSD treating solution necessary
to circulate would depend upon the length of the
interval, tubing volume, and fluid level in the
annulus. The treatment time would depend on
the particular scale deposit, but 24-48 hours of
circulation should be enough. Longer
circulating times may be necessary in extremely
difficult cases. Dilution with well fluids may
slow the disintegration rate.
The best method in determining the most
effective and economical concentration of LSD
for a gypsum removal treatment is to conduct
disintegration rate tests with scale from the well.
However, this is not always possible under field
conditions.
Equations are in this unit for determining the
cubic feet of scale present on the inside and
outside of various pipe sizes. The number of
pounds of gypsum present per linear foot may be
calculated by multiplying 144 x cubic foot of
gypsum present per linear foot. A cubic foot of
gypsum weighs approximately 144 pounds.
Success or failure of a scale removal treatment
often depends upon having sufficient volumes
and concentrations of chemicals. For example,
if a 2 in. I.D. pipe has scale 0.5 in. thick, it
would contain 0.016 cubic feet of gypsum per
linear foot of pipe. Gypsum weighs 144 pounds
per cubic foot so each linear foot of pipe would
contain 2.3 pounds of gypsum. A pipe with a 2
in. I.D. containing 0.5 in. thick scale has a
capacity of 0.0449 gallon per linear foot.
Calculations show 0.0449 gallon of LSD will
theoretically remove 0.314 pounds of gypsum.
So, as many as 5-10 treatments may be required
to remove the scale if a spot and soak technique
is used.
© 2005, Halliburton
10
BaSO4lvent
BaSO4lvent, pronounced (bay-solvent), is a
solution specifically designed to remove barium
sulfate and strontium sulfate scales from
injection wells, disposal wells, gas wells, or
producing wells. BaSO4lvent solution is a one
stage solvent; it does not require an additional
acid stage for the removal of the scale. The use
of BaSO4lvent solution can minimize or
eliminate costly and time-consuming pulling
8 • 51
Stimulation I
Chemical Stimulation
operations and physical descaling of pumps and
tubing. Deposits in perforations, SSSV, and gaslift valves can be removed with BaSO4lvent
solution. By using BaSO4lvent, operators can
more effectively remove NORM (naturally
occurring radioactive material) scale without
exposure to its hazards and eliminate the costly
disposal of these materials.
Equations for Determining
Volume of Scale Present
BaSO4lvent solution can be applied neat or
diluted to a 50% concentration consisting of
freshwater, seawater, or low-hardness brines.
Higher temperatures increase the performance
and reaction rate of BaSO4lvent solution. Any
means of agitation, such as circulation or
periodical pumping of the material back and
forth through scaled perforations, will reduce the
time required for scale removal. Formation
squeezes are effective for removing scale from
the near-wellbore area. Soak and shut-in times
of 8 to 48 hours are recommended. The actual
time required can vary depending on the severity
of the deposit. Before the solvent is used in
downhole well applications, well fluids should
be pumped off or displaced to minimize
interference with the dissolving process at the
problem contact point.
When the deposition of barium sulfate or
strontium sulfate has been diagnosed, the most
practical solution to the problem is to eliminate
the causes. For instance, barium sulfate is most
often formed as a result of high-barium content
injection water being mixed with water that
contains an excess of sulfates. By isolating
these waters, the problem could be eliminated.
If the cause cannot be eliminated, the next most
practical approach is to treat the injection water
or produced water with a scale inhibitor such as
LP-55 to help prevent the deposition of the
scale.
Often, if a simple calcium carbonate scale is to
be removed, the problem is finding how much
15% hydrocholoric acid is needed. It is possible
to use too little acid and fail to effectively
stimulate the well. For example, more than 90
cubic feet of calcium carbonate scale have been
found in some injection wells. For this quantity
of scale, a treatment of at least 8,550 gallons of
15% hydrochloric acid should be used. A
smaller amount of acid may not improve
injectivity and may even decrease it because of
sloughing of the deposit.
The following equations give the scale quantities
in cubic feet for deposits of various thicknesses
on the inside and outside of different pipe sizes.
By measuring the thickness of scale, finding the
length of the scaled interval over which scale is
deposited, and knowing the pipe size, the
amount of scale present can be determined. The
necessary volume of acid or scale removal
solution such as LSD can then be calculated.
Equation 1 is for the calculation of scale volume
on the outside of tubular goods.
(1) V = 0.0218 t (D1 + t)
Equation 2 is for the calculation of scale volume
on the inside of tubular goods.
(2) V = 0.0218 t (D2 – t)
Where
V =
D1 = pipe O.D. in inches
D2 = pipe I.D. in inches
t
Hydra Jet
= scale thickness in inches
Table 8.6 gives the theoretical quantity of 15%
HCL necessary to remove one cubic foot of
various types of scale and the pounds of scale
removed by one gallon of 15% HCL.
A sand laden acid or water wash pumped
through a properly designed jetting device will
remove all types of scale that are not subject to
chemical means of removal. Hydra Jet is
especially valuable in open hole injection wells.
Special tools are available for use in removing
scale from tubing or casing.
© 2005, Halliburton
volume of scale in cubic
feet/linear feet.
Example
Determine the quantity of 15% HCL necessary
to remove an iron sulfide scale having an
8 • 52
Stimulation I
Chemical Stimulation
producing wells. The chemicals used in the
Scalechek® service are three types: solid
Scalechek SCP-2 and HT and liquid Scalechek®
LP-55.
average thickness of 3/8 inch from the outside of
1000 feet of pipe having 3-inch O.D.
Solution
First, use equation 1 to calculate the quantity of
scale per linear foot.
V =
0.0218 t (D1 + t)
V =
0.0218 × 3/8 in. (3in. + 3/8 in.)
SCP-2 is designed to minimize the formation of
scale in producing wells. The chemical nature
of the material allows formation water to pass
over the polyphosphate with only a small
quantity being dissolved. This low
concentration stabilizes the scale-forming
tendency and minimizes scale deposits. SCP-2
is suitable for use in wells having bottom hole
temperatures up to 200°F.
Change 3/8 in. to a decimal and solve for V:
V =
0.0218 × 0.375 × (3 + 0.375)
V =
0.0275906 cubic foot per
linear foot
Now multiply this volume of scale times the
length of pipe to be cleaned to determine the
total volume of scale to be removed. This would
be:
ft 3
ft
3
= 27.5906 ft of iron sulfide scale
Scale Volume = 1000 ft × 0.0275906
The quantity of 15% HCL necessary to remove
iron sulfide is given in Table 8.3. Multiply the
total volume of scale times the quantity of acid
necessary to remove one cubic foot of scale and
the total acid requirement is determined
Acid Volume = 180
gallons 15% HCL
× 27.5906 ft 3
3
ft
Scalechek® treatments with SCP-2 can be
performed with fracturing treatments by mixing
the material with the first 75 % of the propping
agent. Scale forming water flows over or filters
through the granular bed at formation
temperature and pressure and releases a low
concentration of polyphosphates. Most scales
such as calcium carbonate, calcium sulfate, and
barium sulfate can successfully be controlled.
Oil or water base solutions should be used to
carry the SCP-2. Acids tend to cause the rapid
decomposition of all polyphosphates and should
not be used as a placement medium. This does
not mean that acid cannot be used as a
breakdown fluid, providing that an oil or water
spacer is used prior to placing the SCP-2. Wells
which have had polyphosphates placed in them
should not be treated with acid.
= 4966.308 gallons
Scalecheck® HT
Scale Inhibition
Scalechek® HT is a solid scale inhibitor
designed to be placed in a fracturing treatment.
It is placed along with the proppant as a method
of inhibiting the formation of scale.
Incompatibility between scale inhibitors and
fracturing fluids has long been an inherent
problem in stimulation treatments. This
incompatibility results in long or no crosslink
times due to the binding of the phosphate,
phosphonate, or acrylic acid molecule with
crosslinkers such as CL-11, 18, 23, 24, and 29.
Scalechek® HT has been coated to prevent
interference with crosslinked fracturing fluids.
This encapsulation controls the flash release of
inhibitor which affects crosslink time. The high
Scale removal treatments may be expensive, and
the deposition of scale might result in decreased
production. Therefore, it is often more
economical to prevent scale deposition before it
occurs. A number of materials and techniques
are available to help prevent scale deposition.
Scalechek® Scale Prevention
Service
Scalechek® service is a process for preventing
the deposition of scale in injection, disposal and
© 2005, Halliburton
8 • 53
Stimulation I
Chemical Stimulation
concentrations (flash release) of inhibitor
observed in produced water following squeeze
treatments are not likely to occur with
Scalechek® HT. This leaves a higher percentage
of Scalechek® HT in the formation to control
scale compared to squeezed inhibitors.
these kinds of uses, the final concentration of
LP-55 in the treated water should be 5-20 ppm
(parts per million).
Calchek Service
Scalechek® HT is effective in controlling calcite
(calcium carbonate (CaCO3)), gypsum (calcium
sulfate (CaSO4 · 2H2O)), and barite (barium
sulfate (BaSO4)) scales. Scalechek® HT is
effective in preventing Naturally Occurring
Radioactive Material (NORM) scale that is often
associated with barium sulfate scale formation.
Scalechek® HT is effective for temperatures of
100°F and above; it has been evaluated up to
275°F.
Carbonate or sulfate scaling, after acidizing
limestone formations, has been observed in areas
where the formation water contains large
amounts of bicarbonates or sulfates. It has been
found that 0.1% LP-55 in the acid will help
prevent this secondary scaling.
LP-55 is a liquid scale inhibitor containing no
polyphosphates. It is used to help prevent the
deposition of calcium carbonate, calcium sulfate,
and barium sulfate scales in producing and
injection wells. It is a water soluble organic
compound that acts as a crystal poison by
altering the structure of the particles and
preventing growth after a crystal nucleus has
formed.
LP-55 is recommended only as a scale
preventer, not a scale removal compound.
Consequently, it should be used after some
effective descaling treatment has been applied.
Adding LP-55 at a concentration of 0.1% will:
• aid in preventing secondary scaling
• aid in well cleanup
• provide scale protection for short periods of
time
If long-term scale protection is desired, the LP55 concentration should be increased to 0.5 to
0.1% of the treating volume. The shut-in time
for the treating slug should be increased to allow
complete spending of the acid.
The most popular method of placing LP-55 in a
well is with the Chemical Placement Technique
(CPT). The CPT nomograph (Figure 8.2) is
used to determine the volume of water in which
to mix LP-55. This is based on production rate
and desired recovery time. The volume of LP55 to be used is then based on the expected total
water production over the recovery time. For
example, if the recovery time is six months, and
the production total is 5480 bbls, the required
volume can be calculated. LP-55 is used at a
concentration of 0.002 gal/bbl gives 11 gallons
of LP-55. If the CPT nomograph shows that
4,000 gallons of water should be used, then
eleven gallons would be added to 4,000 gallons
of water for placement. LP-55 can be diluted
with water and lubricated down the annulus of
wells or through small tubing strings to treat
water downhole. It can also be metered into
water going into injection or disposal wells. In
© 2005, Halliburton
Many oil operators routinely run remedial acid
treatments on their wells and follow with
inhibitor squeezes after cleaning up the treating
fluids. With the Calchek service, the producers
are able to stimulate their wells with the same
treatment at reduced cost.
The Calchek service treatment is intended for
application in either limestone or dolomite
formations.
Protex-All Inhibitor
Protex-All is a blend of LP-55 and a surfaceactive agent that forms a slowly soluble complex
when placed in contact with an aqueous fluid.
This complex appears to have very high
adhesive properties on tubular goods and on
sandstone and limestone formations. Protex-All
provides long term protection against gypsum,
calcium carbonate, and barium sulfate scales.
The following types of treatments have been
performed in the field:
8 • 54
Stimulation I
Chemical Stimulation
• dumping 1-5 gallons of Protex-All down the
annulus and overflushing with water
length and height of the fracture is required.
The effective permeability of the formation must
also be known so that the fluid loss coefficient
can be calculated. The effective permeability
should include both matrix and fracture
permeability, which is more important in
limestones and dolomites rather than in
sandstones.
• placing Protex-All at a concentration of 1
gallon/1000 in an acid or aqueous fracturing
fluid
• placing 1-5 gallons of Protex-All in water
displacing this dispersion into the formation
If fracture dimensions are not available from
frac plans or effective permeability from logs is
not available, then reasonable values must be
assumed. These will probably vary from one
area to another depending on depth, type of
formation, etc.
Protex-All is only very slightly soluble in
aqueous fluids, but is readily dispersible at low
concentrations.
Notice that Protex-All should be added to the
aqueous carrying fluid on a continuous basis.
Mixing Protex-All in high concentrations with
water or an aqueous fluid will result in a mass
precipitation of the complex. Once this complex
adheres to steel, it is difficult to remove.
Calculations and field evaluations indicate the
following treatment suggestions:
• Effective treatments can be obtained in both
propped and natural or acidized fractures.
• Treatments can be performed on previously
fractured wells or along with fracturing jobs.
Chemical Placement Technique
(CPT)
• Injection rates should be maintained at 1
BPM or lower while placing the chemical
solutions.
CPT is a method of placing chemical solutions
having high fluid loss properties into producing
formations to achieve slow feed-back with the
produced fluids. This technique can provide
long term control of scale and paraffin
deposition by using solutions of Scalechek LP55 or Parachek. Emulsion breakers, corrosion
inhibitors, foaming agents, bactericides and
alcohols can also be placed for slow feed back.
• No fluid loss additives should ever be
incorporated into the chemical solutions.
• The well should be left shut in for several
hours to permit pressure to dissipate.
• Recovery times of 6 months to 15 months
have been achieved using LP-55 in water at
a concentration of 10 gallons/1000 gallons.
The placement of chemical solutions must be
done in formations that contain natural fractures,
induced fractures that are propped, or along with
a fracturing treatment. This is necessary since
the slow return of the chemicals is a result of the
pressure drop profile or flow patterns that exist
in a fractured formation. Injection into an
unfractured formation will result in a fairly rapid
return of the chemicals.
It is possible to place two or more treating
chemicals into a formation together. However,
this requires careful selection to avoid
incompatibility. Chemicals that are highly
adsorbed on formation rock require increased
treating levels to be effective (such as some
emulsion breakers and corrosion inhibitors).
Adsorption will not completely inactivate the
materials. In fact, it will probably increase the
recovery time but decrease the concentration
being returned. With corrosion inhibitors in
sandstone formations, as much as 50% of the
chemical injected in the initial treatment may
never be recovered. However, on subsequent
treatments nearly 100% will be recovered.
Equations have been developed which permit
calculation of total feed back time and also the
initial concentration of chemical being returned
in the produced fluids. In order to use the
equations, there are a number of things that must
be known or assumed about the formation.
First, the equations were developed for flow in a
vertical fracture system. Knowledge of the
© 2005, Halliburton
8 • 55
Stimulation I
Chemical Stimulation
Figure 8.11 – CPT Nomograph
© 2005, Halliburton
8 • 56
Stimulation I
Chemical Stimulation
Unit I Quiz
Fill in the blanks with one or more words or select the correct answer(s) to check your progress in
Unit I.
1. Scale deposits can be found in ____________________ ____________________,
____________________, ____________________, and ____________________
____________________ .
2. Scales are classified as ____________________ ___________________, ____________________
____________________, or ____________________ ____________________.
3. Most scales appear as
______________________________________________
______________________________________________
______________________________________________
4. Which of the following fluids can be used to remove acid soluble scales? (check all that apply)
_____a)
Regular Acid
_____b)
Penetrating Acid
_____c)
Diesel
_____d)
NE Acid
_____e)
Fe Acid
_____f)
Xylene
_____g)
MSA
_____h)
Water
_____i)
PAD
5. ____________________, ____________________ ____________________,
____________________ and ____________________ are chemical methods of removing acid
insoluble scales.
6. Scale formation can be inhibited with:
_____a)
Scalechek LP-55 additive
_____b)
SCP-2
© 2005, Halliburton
8 • 57
Stimulation I
Chemical Stimulation
_____c)
Calchek service
_____d)
Protex-All inhibitor
_____e)
All of the above
Now, look up the suggested answers in the Answer Key.
© 2005, Halliburton
8 • 58
Stimulation I
Chemical Stimulation
Unit J: Placement Aids
During stimulation operations it is sometimes
necessary to divert the stimulation fluid.
Diverting materials should bridge effectively
and be easily removed. Temporary Bridging
Agents are solids used to divert treating fluids in
stimulation operations and to protect producing
zones during workover operations.
Selection of Bridging Agent
Well Conditions
A series of temporary bridging agents have been
developed for diverting operations involving a
variety of well conditions and a wide range of
temperatures. The selection of the bridging
agent and concentration is based on:
Temporary Bridging Agents
The effectiveness of a Temporary Bridging
Agent is dependent on its particle size
distribution. TBA-110, the first water soluble,
graded (specifically sized), temporary bridging
agent was introduced in 1969. Early in 1970,
TBA-350, the first oil soluble, graded,
temporary bridging agent was introduced. The
bridging efficiency of these graded materials
was readily apparent in the field when pressure
charts were studied.
• formation fluids contacted
• feet of formation
• formation temperature
• physical properties of the formation
• type of well completion
• placement technique
Because of the efficiency of TBA-110 (TBA350 is now obsolete), TLC-80, with a particle
size distribution to help prevent caking and to
divert effectively, has also been added to the
inventory.
Melting Point
A bridging agent should be selected that has a
softening point high enough that it does not
soften before the diverting operation has been
completed. In most treating operations, the
treating fluid preceding the diverting material
cools the formation. Effective diversion may be
accomplished when the normal bottom hole
temperatures exceed the melting point of the
bridging agent.
The graded bridging agents contain particles
ranging from about 0.25 inch to 0.002 inch in
diameter. The larger particles bridge on the
zone. The smaller particles successively bridge
on larger particles until a bridge is built that has
very little permeability. Pressure increases are
then sufficient to register on pressure recording
charts and show effective diversion.
Solubility
Bridging agents previously used that were
ungraded (TLC-W3, TLC-15) bridged
effectively and probably slowed down the flow
of treating fluid into the bridged zone slightly.
However, the slow down was not enough to
show a pressure increase on pressure recording
charts
© 2005, Halliburton
A bridging agent should be soluble in the
produced or injected fluid if possible. Oil
soluble bridging agents are not used in water
injection and disposal wells. Water soluble
bridging agents should not be used in oil wells
and gas wells that are not making water unless
an overflush of water is used to dissolve the
agents. Otherwise, a cleanup operation should
be planned with dilute acid or brine. Some
8 • 59
Stimulation I
Chemical Stimulation
materials will sublime (go from solid to vapor)
in gas wells at the bottom hole temperature and
can be removed without a solvent.
increases the overall effectiveness of the
diverting process.
Carrier Fluid
Well Completion Type
The carrier fluid is an important consideration in
diverting. It should have its specific gravity and
viscosity adjusted to maintain a uniform
dispersion of the bridging agent. The carrier
fluid may be gelled or emulsified. Laboratory
tests show that gel type carrier fluids are less
difficult for the bridging agent to hold in place
than emulsions. The strongest bridge is
probably achieved with carrier fluids having the
minimum viscosity for maintaining a uniform
dispersion of the bridging agent. The lower
viscosity lets the carrier fluid continue to flow
through the bridge for a slightly longer time and
deposit more solids for a stronger, less
permeable bridge. The tail end of the carrier
fluid should then have maximum pumpable
viscosity so that it will not flow through the
bridge and will act as a blanket. This would be
the ideal method of application but would be
difficult to achieve. The most practical option
would be to compromise between maximum
pumpable viscosity and the viscosity necessary
to keep the bridging agent uniformly dispersed.
The type of well completion should be
considered along with the physical properties of
the formation. If the formation to be bridged is
fairly homogeneous and free of vugs or
fractures, consider bridging agents that are
composed of smaller particles. These particles
should not bridge on perforations or fractures,
but instead will bridge on the formation and fill
perforations and channeled areas behind the
casing. Such bridging agents are Matriseal O
and Matriseal OWG.
If the zone contains vugs, fractures or is
composed of coarse sand or gravel that will be
difficult to bridge, a bridging agent such as
TLC-80, TBA-110 or FRAX-160 wax should be
considered. Since bridging may be achieved on
the perforations or on the formation, placement
techniques must be considered.
Placement Techniques
When the graded bridging agents (TLC-80,
TBA-110) are used, special techniques must be
used if they are to pass the perforations and
bridge on the formation. Low concentrations of
bridging agent should be used per gallon of the
carrier fluid, which must be viscous enough to
maintain a uniform dispersion of the solids.
Larger volumes of carrier fluid are then
necessary to transport sufficient bridging agent
through the perforation.
Concentration of Bridging
Agent
The type of well completion and previous well
treatment history will help determine the
quantity of solids required to form a bridge.
Erosion of perforations and presence of voids,
vugs, and fractures are also important factors.
The best volumes of both carrier fluid and
bridging agent vary widely from area to area.
However, a general rule seems to be to use at
least twice the volume of the casing covering the
interval for carrier fluid. The quantity of solids
should depend on type of diversion being
attempted.
If you desire to bridge on perforations, a high
concentration of bridging agent is required in a
carrier fluid which has as low a viscosity as
possible and can still transport the bridging
agent to the perforation.
Decreasing the pump rate when the diverting
material approaches the zone is considered one
of the most important steps in correct placement
techniques. This allows an initial bridge to be
accomplished more easily and quickly and
© 2005, Halliburton
Open hole completions in fractured or vuggy
limestone may require 2-4 pounds of TBA-110
per gallon of carrier fluid. An open hole
8 • 60
Stimulation I
Chemical Stimulation
completion in a highly permeable formation,
free of fractures and vugs, may be bridged and
sealed with 4-6 pounds of TBA-110 per square
foot of open hole surface area. Bridging on 3/8
inch perforations may be achieved with ½ to 2
pounds of TBA-110/gallon of carrier fluid. The
higher concentrations will bridge more quickly,
have less loss of carrier fluid to the formation,
and form a stronger bridge.
zone. The data presented for bridging in open
hole, highly permeable, or lost circulation zones
were obtained using the BB Bed test. The zones
were considered unfractured and non-vugular.
Particle Size Distribution
Effectiveness of a bridging agent is dependent
on its particle size distribution. The efficiency
of various bridging agents is compared in Table
8.7. The data were obtained at 76°F using water
gelled with 100 pounds of WG-6 per 1000
gallons. The specific gravity of the water was
adjusted to maintain a uniform dispersion of the
bridging agent. Bridging agents were used at a
concentration of 28 pounds per gallon. The
carrier fluid containing the bridging agent was
displaced with kerosene using a constant pump
rate of two BPM. The maximum pressure was
recorded.
The bulk density of the solids is also a factor in
determining the concentration to use. TLC-80 is
used at about one-half the TBA-110
concentration. All TLC-80 materials available
will not bridge on a 3/8 inch perforation.
Specific data on bridging agent concentrations
are listed in each bridging agent bulletin. The
data on the perforations were obtained without
formation, or other materials surrounding the
casing, and would simulate bridging on
perforations in a highly fractured or vugular
Pressure Held (psi)
Fracture Width
0.10
0.13
0.16
0.20
0.24
0.32
0.40
TBA-110
+
TLC-15S (graded)
+
Unibeads*
TLC-80** (Velsicol Coarse)
1000
1000
340
0
1000
680
290
0
1000
685
234
No bridge
1000
635
129
No bridge
1000
485
65
No bridge
385
No bridge
40
No bridge
No bridge
No bridge
No bridge
No bridge
Table 8.7 - Bridging Agent Efficiency
*A 1:1 blend of Unibead Buttons and Unibead Wide Range material was used.
**These materials bridged fracture widths shown to have 0 pressure buildup but did not seal. Field operations at higher pump
rates than can be achieved in the laboratory have shown that these materials will achieve some fluid control. However, they are
not expected to be nearly as effective as TBA-110, TLC-15S, TBA-350, or the 1:1 blend of Unibead materials.
+ Obsolete
• disperses readily in aqueous treating fluids
Open-hole completions in fractured or vuggy
limestone may require 2-4 pounds per gallon of
carrier fluid. Bridging on perforations can be
achieved at 0.5-2.0 pounds per gallon.
• aids in maintaining a uniform dispersion of
the polymer
• leaves the sandstone formation water-wet
®
MATRISEAL O
Matriseal® O is used for diverting treating fluids
in wells that have been completed with sand
packs behind slotted liners or sand screens. It is
a finely ground, oil-soluble polymer slurried in a
carrier fluid. The carrier fluid has been carefully
selected to provide a pourable slurry which:
© 2005, Halliburton
8 • 61
The oil-soluble polymer is readily soluble in
most crude oils, kerosene, diesel, and Paragon
(aromatic solvents). Its particle size has been
controlled so that it passes through 20-40 mesh
sand (permeability of about 121 darcies) and
bridges and seals on Oklahoma #1 sand
(permeability of about 9 darcies). Musol® A,
solvent, included in a treating placement fluid
with Matriseal® O softens the Matriseal® O
Stimulation I
Chemical Stimulation
aqueous treating fluid a white precipitate forms
that functions as a fluid-loss additive for
diverting. The slow solubility of this precipitate
in water, oil, and gas enables it to divert
effectively and still have good cleanup
properties for all applications.
diverter particles. The softened particles stick
together and do not divert effectively.
Matriseal® O diverter, compatible with LoSurf259 and LoSurf-300, are the preferred nonemulsifiers for sandstone acidizing. Matriseal®
O can be dispersed in HF acid treating fluid.
The acid flows through the liner and sand pack
and penetrates the formation. The resin
component of Matriseal O filters out on the face
of the formation and diverts acid into areas of
the formation having lower permeability.
Progressive diversion occurs and eventually
distributes acid over the zone.
Musol® A solvent should not be included in
carrier fluids with Matriseal® OWG. The
dissolution rate of Matriseal® OWG increases to
the extent that it will not be effective.
Temporary Bridging Agents in
Conjunction with Temblok
Diverting Materials
The oil soluble polymer is readily soluble in
most crude oils and will be removed when
contacted by produced crude oil. However, at
times it may be desirable to spot a hydrocarbon
solvent (kerosene, diesel or Paragon) over the
zone for rapid removal of the polymer present.
Temblok agents are a series of viscous fluid type
diverting materials available in several varieties
to meet differing application requirements for
stimulation and work-over operations. Due to
their viscous consistency, Temblok materials
resist flow into the formation matrix. Where
vugular or fractured zones are encountered,
granular agents such as the Temporary Bridging
Agents may be incorporated into the Temblok
diverting materials to assist in bridging and
sealing the zone. The Bridging Agent must be
insoluble in the Temblok material selected.
Table 8.8 describes the properties of various
Temblok materials and compatible Temporary
Bridging Agents.
Matriseal® OWG Diverter
Matriseal® OWG is a universal diverting
material that may be used in treating or
completion fluids for injection, disposal, oil and
gas wells. Matriseal® OWG diverter has unique
properties. It is a water clear liquid that may be
metered into the stream on large volume treating
operations, or it may be dispersed readily in the
treating solution when batch mixing. When
MATRISEAL® OWG is dispersed in the
Temblok
Type Fluid
Temblok Time and
Temperature Stability
TBA additives that can be used
if needed
80
Tough Water Gel
1
180-350°F
0.2 to over 30 days
TBA-110
90
Tough Water Gel
2
200-350°F
2 to over 30 days
TBA-110, TLC-80, FRAX-160
100
Tough Water Gel
80-200°F
over 30 days
TBA-110, TLC-80, FRAX-160
Table 8.8 - Temblok/TBA Properties
1.
Should be prepared with saturated salt water for greatest
stability, and to prevent dissolution of TBA-110.
© 2005, Halliburton
2.
8 • 62
Do not use Calcium brines.
Stimulation I
Chemical Stimulation
Unit J Quiz
Fill in the blanks with one or more words or circle the correct answer(s) to check your progress in
Unit J.
1. The effectiveness of a Temporary Bridging Agent is dependent on its ____________________
____________________ ____________________.
2. Bridging agent type and concentration is dependent upon:
_____a) formation fluids
_____b) temperature
_____c) formation interval
_____d) type of formation
_____e) all of the above
3. When the graded bridging agents (TLC-80, TBA-110) are used, special techniques must be used if
they are to pass the perforations and bridge on the formation. ________________ concentrations of
bridging agent should be used per gallon of the carrier fluid.
4. If you desire to bridge on perforations, a ________________ concentration of bridging agent is
required in a carrier fluid which has as ________________ a viscosity as possible and can still
____________________ the bridging agent.
5. Musol® A solvent should not be included in carrier fluids with ____________________ or
____________________ because of dissolving problems.
Now, look up the suggested answers in the Answer Key.
© 2005, Halliburton
8 • 63
Stimulation I
Chemical Stimulation
Unit K: Job Calculations
Three common job types are:
1. Spotting to the end of the tubing or
packer
2 3/8-in. 4.7 Tubing
2. Balanced acid spot
4 1/2-in. 11.6 Casing
3. Flushing and overflushing
We shall go through an example of each.
Calculations for Spotting Acid
to the End of Tubing or Packer
In most wells, it is desirable to place as little
fluid on the formation as possible. Many
chemical placement designs call for the
chemical to be spotted to the end of the treating
tubing by circulating. To spot the acid or
chemical, first find the total capacity of the
tubing using the Red Book:
Top of Acid
⎛ ft
⎞
Tubing Capacity = Depth (ft) × ⎜⎜
factor ⎟⎟
⎝ gal
⎠
Tubing Depth
6,500 ft
Then, subtract the amount of acid from the total
tubing capacity:
Flush Volume = Tubing Depth - Feet of Acid Spotted
Example:
Figure 8.12 – Acid Spotting Example
How much 2% KCL water is needed to spot 250
gal 15% HCL to the bottom of the tubing?
Solution:
Tubing Capacity = 6500 ft × 0.1624
gal
(RedBook )
ft
= 1055.6 gal
Flush Vol = 1055.6 gal − 250 gal
= 805.6 gal
© 2005, Halliburton
8 • 64
Stimulation I
Chemical Stimulation
2 3/8-in. 4.7 Tubing
Calculations for Balanced Acid
Spot
4 1/2-in. 11.6 Casing
Spotting a balanced acid pill may be necessary
for acid soaking and perforating applications.
The equal height (balanced height) of the acid
can be determined with the equation:
Height =
Gallons of acid to be spotted
gal
⎛ gal
⎞
factor(tubing) +
factor(annulus) ⎟
⎜
ft
ft
⎝
⎠
To find the volume of displacement:
Feet of Tubing to Flush
= Tubing Length - Feet of Acid Spotted
Flush Volume
= Feet of Tubing to Flush ×
gal
factor(tubing)
ft
Top of Acid
Tubing Depth
6,500 ft
Note: The ability to spotting a balance acid pill
is based on the assumption that the well fluid
and the acid are the same weight.
Example:
Find the displacement volume necessary to spot
a balance acid pill of 250 gal.
Figure 8.13
Solution:
Acid Height =
250 gal
⎛
gal
gal ⎞
⎜⎜ 0.4227
⎟
+ 0.1624
ft
ft ⎟⎠
⎝
= 427.28 ft
Flush Height = 6500 ft - 427.28 ft = 6072.72 ft
gal
= 986 gal
Flush Volume = 6072.7 ft × 0.1624
ft
© 2005, Halliburton
8 • 65
Stimulation I
Chemical Stimulation
Calculations for Flush and
OverFlush
2 3/8- in. 4.7 Tubin g
4 1 /2- in. 11 .6 Casing
It is a standard practice to flush more than the
volume of tubing after pumping acid. This
ensures that:
•
any acid that is not spent can continue to
penetrate the formation
•
there is no live acid in the tubing to
cause corrosion
•
any secondary precipitates that could
form from the acid reaction are
displaced as far into the formation as
possible
Acid flush volume calculations are done from
the bottom of the perforations or open hole
section. So:
Vol to Pump = Tubing Volume
+ Casing Volume to the Bottom Perf
+ Overflush Volume
Example:
Calculate the volume needed to overflush an
acid job by 1 barrel per foot of perforations.
Tubing Depth
6,500 ft
Top Perf
6,700 ft
Bot tom Perf
6,8 00 f t
Figure 8.14
Solution:
gal
= 1005.60 gal
ft
gal
Casing Vol = 300 ft × 0.6528
= 195.84 gal
ft
bbl
42 gal
Overflush = 1
×
× 100 ft
ft of perfs
bbl
= 4200 gal
Vol to Pump = 1005.6 gal + 195.84 gal + 4200 gal
= 5401.44 gal
Tubing Vol = 6500 ft × 0.1624
© 2005, Halliburton
8 • 66
Stimulation I
Unit Quiz K:
1. Well Information:
Casing – 5.5, 23 lb/ft L-55 to 10,200 ft
Tubing – 2-7/8”, 6.5 lb/ft N-80 with a packer set at 9,850 ft
Perforations – 10,030 – 10, 050 ft
Calculate the displacement necessary to spot 2000 gallons of 10% FE acid to the end of the tubing.
2. Well Information:
Casing – 5-1/2”, 15.5 lb/ft N-80 to 9,500 ft
Tubing – 2-7/8” 6.5 lb/ft N-80 to 8,500 ft
Perforations – 8,500 – 8,550
Assumption: Hole is full of a uniform weight of fluid.
Calculate the volume of flush necessary to set a balanced spot of acid at the top of the perforations.
© 2005, Halliburton
8 • 67
Stimulation I
Chemical Stimulation
Self-Check Test for Section 8: Chemical Stimulation
Mark the single best answer to the following questions.
1. ______ True
______ False
The major acids used in chemical stimulation are HCL and HF.
2. ______ True
______ False
Commercially available HCL can be 20 °Be or 22 °Be.
3. ____________________________ acid is the only acid that will not damage chrome.
4. Check what procedures to observe when working with acid.
_____a.
wear goggles
_____b.
have sodium bicarbonate available
_____c.
wash eyes with strong water jet
_____d.
smoke around acid tanks
_____e.
add acid to water
5. If you have 22°Be acid, how much acid and water are required for 750 gallons of 7% HCL?
__________ gal acid
__________ gal water
6. ______ True
______ False
Inhibitors decrease the corrosion rate of acid on steel pipe.
7. ______ True
______ False
Halliburton corrosion inhibitors will protect metals other than steel,
such as aluminum and magnesium.
8. ______ True
______ False
Matrix acidizing is done at rates and pressures below fracturing
pressure.
9. Emulsion break tests are run with ___________________ ___________________ and
____________________ _______________________. Complete separation of oil and acid in
_____________________ to _____________________ minutes is desirable.
10. ______ True ______ False
HF Acid is used to dissolve limestone out of a sandstone formation.
11. ______ True
HF Acid’s rate of spending is constant; it never changes.
______ False
12. The major retarded HF system Halliburton offers is:
_____a.
Sandstone Acid
_____b.
FE
_____c.
ClaySol
_____d.
ClayFix
_____e.
Fines Control Acid
13. ______ True ______ False
HF Acid can react with limestone to form an insoluble precipitate.
14. ______ True
Spent HF Acid can react with sodium and potassium to form more
HF acid.
______ False
15. Damage to a formation results when invasion of which of the following occurs?
© 2005, Halliburton
8 • 68
Stimulation I
Chemical Stimulation
a. ______ Clay
b. ______ Whole mud
c. ______ Filtrate
d. ______ All of the above
16. ______ True ______ False
If the formation is limestone, mud damage can be removed with HCL
or HF.
17. The cloud point of an oil is __________________________________________________.
18. The pour point of an oil is ___________________________________________________.
19. Paraffin can be removed ____________________, ______________________, and with
____________________.
20. Scales are classified as __________________ _________________ or _______________
________________.
21. List three methods of removing acid insoluble scales.
________________________________________________
________________________________________________
________________________________________________
22. What are two products used for scale inhibition?
______________________
______________________
23. ______ True
______ False
Particle size determines how effective TBA agents are.
24. ______ True ______ False
TBA products should be insoluble in formation fluids.
25. TBA agents can be placed using
a. ______ acids
b. ______ emulsions
c. ______ gels
d. ______ Temblok
e. ______ all of the above
Now, look up the suggested answers in the Answer Key at the end of this section.
© 2005, Halliburton
8 • 69
Stimulation I
Chemical Stimulation
Answer Key
Items from Unit A Quiz
1. hydrochloric, hydrofluoric, organic
2. damage removal / matrix / fracture
3. 20 / 31.45
4. sandstone
5. Formic / acetic
6. acetic
Items from Unit B Quiz
1. Goggles
2. sodium bicarbonate
3. skin / eyes
4. hydrogen gas
5. water / acid
6. dust mask
Items from Unit C Quiz
1. 1843
2. 2050 / gallons / water / 6620 / carbon dioxide
3. 1020
4. 288 acid / 712 gal water
Items from Unit D Quiz
1. temperature, time of contact, type of acid, pressure, type of steel, ratio of volume of acid to exposed
steel surface area.
2. Ff.)
3. HII 124 / HHII 500
4. Ff.)
5. 0.05
6. Organic
Items from Unit E
1. skin
© 2005, Halliburton
8 • 70
Stimulation I
Chemical Stimulation
2. fracturing
3. collapse / coning / scaling
4. fracture acidizing
5. preflushes / cool
6. F
7. b
8. c
9. sustained – production acidizing
Items from Unit F
1. a, c
2. e
3. physical and chemical composition of the formation, temperature, surface area of rock exposed to a
particular volume of acid, concentration of excess hydrochloric acid
4. Clayfix
5. hydrocarbons / invasion / emulsions
6. Fines Removal Acid
Items from Unit G Quiz
1. filtrate / clay / whole mud
2. Acid / Mud flush
3. F
4. Oil External Emulsions / True Oil Base
5. N-Ver-Sperse A / N-Ver-Sperse O
Items from Unit H Quiz
1. T
2. F
3. temperature / solution
4. temperature / flow
5. The alternate coating of the pipe and draining of the oil, The presence of only a film of oil in contact
with the pipe while the well is flowing oil through water zones, Rough pipe surface, Electrical charger
on various materials in the crude oil, Temperature drop
6. F
7. Mechanical equipment, Solvents which dissolve the deposits, Heat, which melts the wax and reduces
it to a liquid so that it can be easily removed
8. Crystal modifiers
9. Targon II / Tarchek
© 2005, Halliburton
8 • 71
Stimulation I
Chemical Stimulation
Items from Unit I Quiz
1. Flow liner / tubing / perforations / formation face
2. water soluble / acid soluble / acid insoluble
3. Thin sealer or popcorn like laminated deposits crystalline deposits
4. a, b, d, e, g, i
5. GYPSOL, Liquid Scale Disintegrator, BaSo4lvent
6. e
Items from Unit J Quiz
1. particle size distribution
2. e.)
3. formation
4. high / low / transport
5. Matriseal OWG / Matriseal O
Items from Unit K Quiz
1.
2.
gal
= 2394.54 gal
ft
Flush Volume = 2394.54 gal - 2000 gal = 394.54 gal
Tubing Capacity = 9850 ft × .2431
gal
gal
factor for 2 - 7/8" tubing = 0.2431
ft
ft
gal
gal
factor for 5 - 7/8" casing = 0.6625
ft
ft
500 gal
Acid Height =
= 552.12 ft
gal
gal ⎞
⎛
+ 0.6625
⎜ 0.2431
⎟
ft
ft ⎠
⎝
gal
= 1932.13 gal
Flush Vol = (8500 ft - 552.12 ft ) × 0.2431
ft
© 2005, Halliburton
8 • 72
Stimulation I
Chemical Stimulation
Self Check Test
1. T
2. T
3. Acetic
4.
a, b, e
5. 175 acid / 825 water
6. T
7. F
8. T
9. produced fluid / treating solution / ten / fifteen
10. F
11. F
12. e
13. T
14. F
15. d
16. F
17. the cloud point is the temperature where paraffin begins to come out of solution.
18. Pour point is the temperature where oil will not flow when tilted to a horizontal position
19. mechanically /, solvents which dissolve paraffin, / heat which melts the way and reduces it to a liquid
20. water soluble /, acid soluble /, acid insoluble
21. GypsolYPSOOL, Liquid Sacle Disintegrator, BaSO4lvent
22. SCP-2 / Scalecheck, LP-55
23. T
24. F
25. e
© 2005, Halliburton
8 • 73
Stimulation I